<PAGE>
File No. 70-09623
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------------------
AMENDMENT NO. 1
TO
FORM U-1
-------------------------------
APPLICATION OR DECLARATION
under the
PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
* * *
AMERICAN ELECTRIC POWER COMPANY, INC.
1 Riverside Plaza, Columbus, Ohio 43215
---------------------------------------
(Name of company or companies filing this statement
and address of principal executive office)
* * *
AMERICAN ELECTRIC POWER COMPANY, INC.
1 Riverside Plaza, Columbus, Ohio 43215
---------------------------------------
(Name of top registered holding company
parent of each applicant or declarant)
* * *
A. A. Pena, Senior Vice President and Treasurer
American Electric Power Service Corporation
1 Riverside Plaza, Columbus, Ohio 43215
---------------------------------------
Susan Tomasky, Executive Vice President and General Counsel
American Electric Power Service Corporation
1 Riverside Plaza, Columbus, Ohio 43215
---------------------------------------
(Names and addresses of agents for service)
<PAGE>
American Electric Power Company, Inc. hereby amends its Declaration on Form
U-1, in File No. 70-09623, as follows:
ITEM 6. EXHIBITS AND FINANCIAL STATEMENTS
---------------------------------
The following exhibits are filed as part of this statement:
(a) Exhibits:
A-2 Notice of 2000 Annual Meeting and Proxy Statement.
A-3 Form of proxy card.
SIGNATURE
---------
Pursuant to the requirements of the Public Utility Holding Company Act of
1935, the undersigned company has duly caused this Amendment to be signed on its
behalf by the undersigned thereunto duly authorized.
AMERICAN ELECTRIC POWER COMPANY,INC.
By: /s/ H. W. Fayne
---------------------------------
H. W. Fayne
Vice President and
Chief Financial Officer
March 6, 2000
<PAGE>
Notice of 2000 Annual Meeting . Proxy Statement
American Electric Power
Company, Inc.
1 Riverside Plaza
Columbus, OH 43215
E. Linn Draper, Jr.
Chairman of the Board,
President and
Chief Executive Officer
[LOGO OF AMERICAN ELECTRIC POWER]
March 10, 2000
Dear Shareholder:
This year's annual meeting of shareholders will be held at The Ohio State
University's Fawcett Center, 2400 Olentangy River Road, Columbus, Ohio, on Wed-
nesday, April 26, 2000 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.
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 rec-
ord, you will receive instructions from the holder of record that you must fol-
low 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 7 which will enable you to gain admittance
to the meeting.
Sincerely,
/s/ E. L. Draper, Jr.
<PAGE>
NOTICE OF 2000 ANNUAL MEETING
--------------------------------------------------
American Electric Power Company, Inc.
1 Riverside Plaza
Columbus, Ohio 43215
--------------------------------------------------
<TABLE>
<C> <S>
TIME............... 9:30 a.m. on Wednesday, April 26, 2000.
PLACE.............. Fawcett Center
The Ohio State University
2400 Olentangy River Road
Columbus, Ohio
ITEMS OF BUSINESS.. (1) To elect 15 directors to hold office until the next
annual meeting and until their successors are duly
elected. Of these 15 directors, six directors of
Central and South West Corporation ("CSW") are to be
elected only if, before the meeting, the merger of AEP
and CSW is consummated and such persons have been
named to AEP's Board.
(2) To approve the firm of Deloitte & Touche llp as
independent auditors for the year 2000.
(3) To consider and act on a proposal to approve the
American Electric Power System 2000 Long-Term
Incentive Plan.
(4) To consider and act on such other matters as may
properly come before the meeting.
RECORD DATE........ Only shareholders of record at the close of business on
March 7, 2000 are entitled to notice of and to vote at the
meeting or any adjournment thereof.
ANNUAL REPORT...... Appendix A to this proxy statement has AEP's audited
financial statements and management's discussion and
analysis of results of operations and financial condition.
AEP's Summary Report to Shareholders contains Dr. Draper's
letter to shareholders, condensed financial statements, a
summary discussion of results of operations and financial
condition, and an independent auditors' report.
PROXY VOTING....... It is important that your shares be represented and voted
at the meeting. Please vote in one of these ways:
(1) MARK, SIGN, DATE AND PROMPTLY RETURN the enclosed
proxy card in the postage-paid envelope.
(2) USE THE TOLL-FREE TELEPHONE NUMBER shown on the proxy
card.
(3) VISIT THE WEB SITE noted on your proxy card to vote
via the Internet.
Any proxy may be revoked at any time prior to its exercise
at the meeting.
</TABLE>
March 10, 2000 Susan Tomasky
Secretary
<PAGE>
Proxy Statement
March 10, 2000
Proxy and Voting Information
This proxy statement and the accompanying proxy card are to be mailed to
shareholders, commencing on or about March 14, 2000, 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 26, 2000 in Columbus, Ohio.
Who Can Vote. Only the holders of shares of Common Stock at the close of
business on March 7, 2000 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 194,103,349 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 reg-
istered in their names and the whole shares held in their Plan accounts on
March 7, 2000. 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, each
other matter by marking the appropriate boxes 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 re-
voked, 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.
However, with respect to the proposal regarding the AEP System 2000 Long-Term
Incentive Plan, abstentions and broker non-votes will have the same effect as
votes "against" this proposal, since the affirmative vote of holders of a ma-
jority of the outstanding shares is required for approval. 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 exer-
cised 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 iden-
tify 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 ma-
terial. 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 ad-
dress, at your request, mailing of the duplicate copy to the account you se-
lect 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.
<PAGE>
1. Election of Directors-- Pending CSW Merger
On December 21, 1997, AEP and Central and South West Corporation ("CSW") en-
tered 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.
Pursuant to the merger agreement, at the effective time of the merger, Mr.
E. R. Brooks, chairman and chief executive officer of CSW, and Drs. Donald M.
Carlton and Richard L. Sandor and Messrs. William R. Howell and James L. Pow-
ell, outside directors of CSW, will become directors of AEP. In addition, at
the effective time of the merger, Mr. Thomas V. Shockley, III, president and
chief operating officer of CSW, will also become a director of AEP. The merger
was not yet consummated before the date of this proxy statement, but may be
consummated before the annual meeting. Consequently, information is given for
these persons assuming their election to the AEP Board prior to the annual
meeting.
If the merger is not consummated prior to the annual meeting, only the nine
nominees, other than Messrs. Brooks, Howell, Powell and Shockley and Drs.
Carlton and Sandor, will be considered for election to AEP's Board of Direc-
tors at the annual meeting. In this case, these six CSW directors will be ap-
pointed to the AEP Board upon the consummation of the merger and stand for
election at the 2001 annual meeting of shareholders. There are no arrangements
or understandings between AEP and any person pursuant to which that person has
been selected as a director or nominee except with respect to these six CSW
directors.
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 February 23, 2000, the Board of Directors adopted a resolution reducing
the number of directors by one, effective on the date of the annual meeting.
Judge Robert M. Duncan, a director, will be retiring from the Board and not
standing for reelection.
The 15 nominees named on pages 3-7 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 nomi-
nees, 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 1999 annual meeting, except for
Messrs. Brooks, Howell, Powell and Shockley and Drs. Carlton and Sandor. 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.
Cumulative Voting. 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 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.
Biographical Information. The following brief biographies of the nominees
include their principal occupations, ages on the date of this statement, ac-
counts 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
24.
2
<PAGE>
Nominees For Director
John P. DesBarres Received an associate degree in
electrical engineering from
[PHOTO] Worcester Junior College in 1960
and completed the Harvard Business
Investor/Consultant, School Program for Management De-
Rancho Palos Verdes, Califor- velopment in 1975 and the Massa-
nia chusetts Institute of Technology
Sloan School Senior Executive Pro-
Age 60 gram in 1984. Joined Sun Company
(petroleum and natural gas) in
Director since 1997 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 ex-
ecutive officer of Sante Fe Pa-
cific Pipelines, Inc. (1988-1991)
(petroleum products pipeline).
President and chief executive of-
ficer (1991-1995) and chairman
(1992-1995) of Transco Energy Com-
pany (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. (chemi-
cal engineering) degrees from Rice
[PHOTO] University in 1964 and 1965, re-
spectively, and Ph.D. (nuclear en-
Chairman, President and gineering) in 1970 from Cornell
Chief Executive Officer University. Joined Gulf States
of AEP and AEP Service Utilities Company, an unaffiliated
Corporation; Chairman electric utility, in 1979. Chair-
and Chief Executive Of- man of the board, president and
ficer of all other major chief executive officer of Gulf
Company subsidiaries States (1987-1992). Elected presi-
dent of AEP and president and
Age 58 chief operating officer of AEP
Service Corporation in March 1992
Director since 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 Man-
agement, Inc., which is the gen-
eral partner of Borden Chemicals
and Plastics L.P., and CellNet
Data Systems, Inc.
- --------------------------------------------------------------------------------
3
<PAGE>
Nominees For Director -- continued
Robert W. Fri Holds a B.A. from Rice University
and an M.B.A. from Harvard Busi-
[PHOTO] ness School. Associated with
McKinsey & Company, Inc., manage-
Director, National Museum ment consulting firm, from 1963 to
of Natural History 1971 and again from 1973 to 1975,
(Smithsonian Institution), being elected a principal in the
Washington, D.C. firm in 1968. From 1971 to 1973,
served as first Deputy Administra-
Age 64 tor of the Environmental Protec-
tion Agency, becoming Acting Ad-
Director since 1995 ministrator in 1973. Was first
Deputy and then Acting Administra-
tor of the Energy Research and De-
velopment Administration from 1975
to 1977. From 1978 to 1986 was
President of Energy Transition
Corporation. President and direc-
tor of Resources for the Future
(non-profit research organization)
from 1986 to 1995 and became se-
nior fellow emeritus in 1996. As-
sumed his present position with
the National Museum of Natural
History in 1996. A director of Ha-
gler Bailly, Inc.
- -------------------------------------------------------------------------------
Lester A. Hudson, Jr. Received a B.A. from Furman Uni-
versity in 1961, an M.B.A. from
[PHOTO] the University of South Carolina
in 1965 and Ph.D. (industrial man-
Professor of Business Strate- agement) from Clemson University
gy, Clemson University, in 1997. Joined Dan River Inc.
Greenville, South Carolina (textile fabric manufacturer) in
1970 and was elected president and
Age 60 chief operating officer in 1981
and chief executive officer in
Director since 1987 1987. Resigned from Dan River in
1990. Joined WundaWeve Carpets,
Inc. (carpet manufacturer) as
chairman, president and chief ex-
ecutive officer in 1990. Chairman
of WundaWeve in 1991. Vice chair-
man of WundaWeve (1993-1995).
Chairman, H&E Associates (invest-
ment firm), 1995-1998. Assumed his
present position with Clemson Uni-
versity in 1998. A director of
American National Bankshares Inc.
and Greenville Hospital System
Foundation.
- -------------------------------------------------------------------------------
4
<PAGE>
Nominees For Director -- continued
Leonard J. Kujawa Received his B.B.A. in 1954 and
M.B.A. in 1955 from the University
[PHOTO] of Michigan. Joined Arthur Andersen
LLP (accounting and consulting
firm) in 1957 and became a partner
in 1968, specializing in the elec-
tric and telecommunications indus-
tries. Worldwide Director Energy
and Telecommunications (1985-1995).
Retired in 1995. International en-
ergy consultant to his former firm
and other global companies. A di-
rector of Schweitzer-Mauduit Inter-
national, Inc.
International Energy Consul-
tant,
Atlanta, Georgia
Age 67
Director since 1997
- --------------------------------------------------------------------------------
Donald G. Smith Joined Roanoke Electric Steel Cor-
poration (steel manufacturer) in
[PHOTO] 1957. Held various positions with
Roanoke Electric Steel before being
named president and treasurer in
1985, chief executive officer in
1986 and chairman of the board in
1989.
Chairman of the Board, Presi-
dent, Chief Executive Officer
and
Treasurer of Roanoke Electric
Steel Corporation, Roanoke,
Virginia
Age 64
Director since 1994
- --------------------------------------------------------------------------------
Linda Gillespie Stuntz Holds an A.B. from Wittenberg Uni-
versity (1976) and J.D. from Har-
[PHOTO] vard Law School (1979). Private
practice of law (1979-1981). U.S.
House of Representatives, Committee
on Energy and Commerce: Associate
Minority Counsel, Subcommittee on
Fossil and Synthetic Fuels (1981-
1986) and Minority Counsel and
Staff Director (1986-1987). Private
practice of law (1987-1989). U.S.
Department of Energy (1989-1993):
Acting Deputy Secretary (January
1992-July 1992) and Deputy Secre-
tary (July 1992-January 1993). Re-
turned to the private practice of
law in March 1993. A director of
Schlumberger Limited. Chair, Advi-
sory Council, Electric Power Re-
search Institute.
Partner, Stuntz, Davis &
Staffier,
P.C., attorneys, Washington,
D.C.
Age 45
Director since 1993
- --------------------------------------------------------------------------------
Kathryn D. Sullivan Received her B.S. from the Univer-
sity of California and Ph.D. from
[PHOTO] Dalhousie University. NASA space
shuttle astronaut (1978-1993).
Chief Scientist at the National
Oceanic and Atmospheric Administra-
tion (1993-1996). Became president
and chief executive officer of Co-
lumbus' science museum COSI (Center
of Science & Industry) in 1996.
U.S. Naval Reserve Officer. A di-
rector of McDermott International,
Inc.
President and Chief Executive
Officer, COSI Columbus,
Columbus, Ohio
Age 48
Director since 1997
- --------------------------------------------------------------------------------
5
<PAGE>
Nominees For Director -- continued
Morris Tanenbaum Graduated from The Johns Hopkins
University in 1949 with a B.A. in
[PHOTO] chemistry and received a Ph.D. in
physical chemistry in 1952 from
Director and Trustee, Princeton University. Joined Bell
Short Hills, New Jersey Telephone Laboratories in 1952 and
held various positions with AT&T
Age 71 companies. Became vice chairman of
the board of AT&T in 1986 and
Director since 1989 chief financial officer in 1988.
Retired in 1991. A trustee of Mas-
sachusetts Institute of Technolo-
gy, associate trustee of Battelle
Memorial Institute, trustee emeri-
tus of The Johns Hopkins Universi-
ty, honorary trustee of The
Brookings Institution and a member
of the National Academy of Engi-
neering.
- --------------------------------------------------------------------------------
CSW Nominees for Director
(Assumes Prior Election to the Board as Described on Page 2)
E. R. Brooks Received his B.S. (electrical en-
gineering) from Texas Tech Univer-
[PHOTO] sity in 1961. Chairman and chief
executive officer of Central and
Chairman and Chief Executive South West Corporation since Feb-
Officer, Central and South ruary 1991. Served as CSW's presi-
West dent from February 1991 to July
Corporation, Dallas, Texas 1997. A director of each of CSW's
subsidiaries and of Hubbell, Inc.
Age 62 A trustee of Baylor Health Care
Center, Dallas, Texas, Hardin-
Simmons University, Abilene, Tex-
as, and Texas Tech University,
Lubbock, Texas.
- --------------------------------------------------------------------------------
Donald M. Carlton Received his B.A. from the Univer-
sity of St. Thomas in Houston in
[PHOTO] 1958 and Ph.D. (organic chemistry)
from the University of Texas at
Austin in 1962. President and
chairman of Radian Corporation, an
engineering and technology firm,
from 1969 through December 1995.
Named president and chief execu-
tive officer of Radian Interna-
tional LLC in January 1996 and re-
tired as of December 31, 1998. A
director of Concert Investment Se-
ries Funds, National Instruments
and Valero Energy Corporation.
Retired President and Chief
Executive Officer, Radian
International LLC, Austin,
Texas
Age 61
- --------------------------------------------------------------------------------
6
<PAGE>
CSW Nominees for Director -- continued
(Assumes Prior Election to the Board as Described on Page 2)
William R. Howell Received his B.B.A. from the Uni-
versity of Oklahoma in 1958. Joined
[PHOTO] J.C. Penney Company (major retail-
er) in 1958 and held various mana-
gerial positions. Chairman of the
board of J. C. Penney Company from
1983 to January 1997 and also chief
executive officer from 1983 to Jan-
uary 1996. Chairman emeritus of J.
C. Penney Company (1997-present).
Chairman of the Board of Trustees
of Southern Methodist University
since 1996. A director of Exxon Mo-
bil Corporation, Warner-Lambert
Company, Bankers Trust, Halliburton
Company and Williams.
Chairman Emeritus, J. C.
Penney
Company, Inc., Dallas, Texas
Age 64
- --------------------------------------------------------------------------------
James L. Powell Received his bachelor's degree from
Rice University in 1951. Involved
[PHOTO] in ranching and investments in Fort
McKavett, Texas, since 1956. Member
of University of Texas System Chan-
cellor's Council, Rice University
Associates and Board of Visitors of
University of Texas M.D. Anderson
Hospital. An advisory director of
First National Bank, Mertzon, Tex-
as.
Ranching and Investments,
Fort McKavett, Texas
Age 70
- --------------------------------------------------------------------------------
Received his B.A. from City Uni-
Richard L. Sandor versity of New York, Brooklyn Col-
lege, and Ph.D. (economics) from
[PHOTO] the University of Minnesota.
Chairman and chief executive offi-
cer of Environmental Financial
Products, LLC (developes and
trades in new environmental, fi-
nancial and commodity markets)
since March 1993. Second vice
chairman of the Chicago Board of
Trade (1997-1998). A director of
Nextera Enterprises, Inc.
Chairman and Chief
Executive
Officer, Environmental
Financial
Products, LLC, Chicago,
Illinois
Age 57
- --------------------------------------------------------------------------------
Thomas V. Shockley, III Received his B.S. (electrical en-
gineering) from Texas A&I Univer-
[PHOTO] sity in 1967 and M.S. (electrical
engineering) from the University
of Texas at Austin in 1969. Presi-
dent and chief operating officer
of Central and South West Corpora-
tion since July 1997. Joined CSW
as senior vice president in Janu-
ary 1990 and became an executive
vice president in September of
that same year. A director of each
of CSW's non-electric
subsidiaries.
President and Chief
Operating
Officer, Central and South
West
Corporation, Dallas, Texas
Age 54
- --------------------------------------------------------------------------------
Dr. Draper is a director of Ap- subsidiaries of AEP with one or
palachian Power Company, Columbus more classes of publicly held pre-
Southern Power Company, Indiana ferred stock or debt securities)
Michigan Power Company, Kentucky and other subsidiaries of AEP. Dr.
Power Company and Ohio Power Com- Draper is also a director of AEP
pany (all of which are Generating Company, a subsidiary
of the Company.
7
<PAGE>
Related Transactions
Dr. Draper's son is a partner in the law firm of Winston & Strawn which AEP re-
tained during 1999 and which AEP is retaining during 2000 for matters primarily
relating to the restart of the Cook Nuclear Plant. Dr. Draper's son has not
been involved with any AEP legal matters.
Functions of the Board of Directors and Committees
Under New York law, AEP is managed under the direction of the Board of Direc-
tors. The Board establishes broad corporate policies and authorizes various
types of transactions, but it is not involved in day-to-day operational de-
tails. During 1999, the Board held eight regular and five special meetings. The
Board has seven standing committees, the functions of which are described in
the following paragraphs.
The Audit Committee oversees, and reports to the Board concerning, the gen-
eral policies and practices of AEP and its subsidiaries with respect to ac-
counting, 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 and Fri and Drs. Hudson
and Sullivan.
Audit Committee meetings in 1999: 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 ap-
pointment to fill vacancies on the Board as they occur and the slate of nom-
inees for election at the annual meeting.
The Committee on Directors will consider shareholder recommendations of can-
didates 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 1999: two.
The Corporate Public Policy Committee is responsible for examining AEP's
policies on major public issues affecting the AEP System, including environmen-
tal, work force diversity, industry change and other matters, as well as estab-
lished System policies which affect the relationship of AEP and its subsidiar-
ies 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 and Smith, Drs. Hudson, Sullivan and Tanenbaum and Ms. Stuntz.
Corporate Public Policy Committee meetings in 1999: four.
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.
8
<PAGE>
Executive Committee members: Drs. Draper and Tanenbaum and Ms. Stuntz.
Executive Committee meetings in 1999: 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 subsidiar-
ies 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.
Finance Committee members: Messrs. Kujawa and Smith, Ms. Stuntz and Dr.
Tanenbaum.
Finance Committee meetings in 1999: 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 Corpo-
ration officers who hold the position of Senior Vice President or higher of-
fice.
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. Hud-
son and Tanenbaum.
Human Resources Committee meetings in 1999: five.
The Nuclear Oversight Committee is responsible for overseeing and reporting
to the Board with respect to the management and operation of AEP's Cook Nuclear
Plant.
Nuclear Oversight Committee members: Messrs. DesBarres and Fri, Ms. Stuntz
and Drs. Sullivan and Tanenbaum.
Nuclear Oversight Committee meetings in 1999: four.
During 1999, 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 em-
ployees 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.
Deferred Compensation and Stock Plan. The Deferred Compensation and Stock
Plan for Non-Employee Directors permits non-employee directors to choose to re-
ceive 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 termina-
tion 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
9
<PAGE>
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 ac-
crue as additional Stock Units. Payment of Stock Units to a director from de-
ferrals 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-Em-
ployee 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 pay-
ment 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 pro-
vide a $1,000,000 accidental death benefit for each director (three-year pre-
mium 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 (ex-
cluding 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 ($390 for 1999).
Stock Ownership Guidelines. AEP's Board of Directors considers stock owner-
ship 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 di-
rectors. The target for each non-employee director is 2,000 shares of AEP Com-
mon 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 di-
rectors and officers for any such losses. Such insurance is provided by Asso-
ciated Electric & Gas Insurance Services, Energy Insurance Mutual, CNA, Great
American Insurance Company, Zurich American Insurance Company, Zurich UK, and
The Federal Insurance Company, effective January 1, 2000 through December 31,
2000, and pays up to an aggregate amount of $250,000,000 on any one claim and
in any one policy year. The total annual cost for the seven policies is
$1,027,689.
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 im-
posed under the Employee Retirement Income Security Act of 1974. This cover-
age, 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 cost 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 ap-
pointed the accounting firm of Deloitte & Touche llp as independent auditors
of AEP for the year 2000, subject to approval by the shareholders at the
10
<PAGE>
annual meeting. Deloitte & Touche llp is considered to be the firm best quali-
fied to perform this important function because of its ability and the famil-
iarity of its personnel with AEP's affairs. It and predecessor firms have been
AEP's auditors since 1911.
Worldwide fees billed by Deloitte & Touche llp and Deloitte Consulting llc
for accounting and auditing, tax, merger assistance, and other professional
services rendered to AEP and its subsidiaries during 1999 were $9,240,000.
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 meet-
ing.
Your Board of Directors recommends a vote FOR approval of Deloitte & Touche
llp as independent auditors for 2000.
3. Approval of AEP 2000 Long-Term Incentive Plan
The Board of Directors adopted the American Electric Power System 2000 Long-
Term Incentive Plan ("2000 Plan") on January 26, 2000, subject to approval by
the shareholders at the annual meeting and approval by the Securities and Ex-
change Commission under the Public Utility Holding Act of 1935.
The 2000 Plan will allow the grant of incentive awards to employees of the
AEP System and to nonemployee members of the Board of Directors. The 2000 Plan
provides for the grant of stock options, including incentive stock options and
nonqualified stock options, as well as stock appreciation rights, restricted
stock, performance awards, phantom stock, and dividend equivalents, as de-
scribed below.
The purpose of the 2000 Plan is to promote the interests of AEP and its
shareholders by strengthening AEP's ability to attract, motivate and retain
employees and directors, to align further the interests of AEP's management
with the shareholders, and to provide an additional incentive for employees
and directors to promote the financial success and growth of AEP. The 2000
Plan is designed to allow for the grant of certain types of awards that con-
form to the requirements for tax deductible "performance-based" compensation
under Section 162(m) of the Internal Revenue Code, as discussed under Tax Pol-
icy in the section of this proxy statement entitled Board Human Resources Com-
mittee Report on Executive Compensation. The 2000 Plan is intended to replace
AEP's Performance Share Incentive Plan.
The Human Resources Committee expects to consider approximately 250 employ-
ees for participation in the 2000 Plan. The number of persons eligible to par-
ticipate in the 2000 Plan and the number of grantees may vary from year to
year.
The closing price of AEP's Common Stock on March 1, 2000, was $27.56 per
share.
Summary of the 2000 Plan
The full text of the 2000 Plan is set forth in Exhibit A to which reference is
made. The following description of certain features of the 2000 Plan is quali-
fied in its entirety by this reference.
Reservation of Shares. AEP has reserved, subject to shareholder and SEC ap-
proval of the 2000 Plan, 9,500,000 shares of Common Stock for issuance under
the 2000 Plan. The shares to be delivered under the 2000 Plan will be made
available from authorized but unissued shares and/or shares reacquired by AEP.
If any shares of Common Stock that are the subject of an award are not issued
and cease to be issuable for any reason, such shares will no longer be charged
against such maximum share limitation and may again be made subject to awards
under the 2000 Plan. In the event of certain corporate reorganizations, recap-
italizations, or other specified corporate transactions affecting AEP or the
Common Stock such as the proposed merger of AEP with Central and South West
Corporation, proportionate adjustments may be made to the number of shares
available for grant under the 2000 Plan, the applicable maximum share limita-
tions under the 2000 Plan, and the number of shares and prices under outstand-
ing awards at the time of the event.
11
<PAGE>
Administration. The 2000 Plan will be administered by the Human Resources
Committee of the Board of Directors (the "Committee"). Subject to the limita-
tions set forth in the 2000 Plan, the Committee has the authority to determine
the persons to whom awards are granted, the types of awards to be granted, the
time at which awards will be granted, the number of shares, units or other
rights subject to each award, the exercise, base or purchase price of an award
(if any), the time or times at which the award will become vested, exercisable
or payable, and the duration of the award. The Committee may provide for the
acceleration of the vesting or exercise period of an award at any time prior
to its termination or upon the occurrence of specified events. With the con-
sent of the affected participant, the Committee has the authority to cancel
and replace awards previously granted with new awards for the same or a dif-
ferent number of shares and for the same or different exercise or base price
and may amend the terms of any outstanding award, provided that the Committee
shall not have the authority to reduce the exercise or base price of an award
by amendment or cancellation and substitution of an existing award without ap-
proval of AEP's shareholders. With respect to awards granted under the 2000
Plan to nonemployee members of the Board of Directors, all rights, powers and
authorities vested in the Committee under the 2000 Plan shall instead be exer-
cised by the nonemployee members of the Board.
Eligibility. All employees of AEP and its subsidiaries and all nonemployee
members of the Board of Directors are eligible to be granted awards under the
2000 Plan, as selected from time to time by the Committee in its sole
discretion.
Stock Options. The 2000 Plan authorizes the grant of nonqualified stock op-
tions and incentive stock options. Nonqualified stock options may be granted
to employees and nonemployee directors. Incentive stock options may only be
granted to employees. The exercise price of an option may be determined by the
Committee, provided that the exercise price per share of an option may not be
less than 100% of the fair market value of a share of Common Stock on the date
of grant, unless options are assumed in certain transactions identified in the
Internal Revenue Code. Stock options may be granted for any term specified by
the Committee, subject to the provisions of the Internal Revenue Code relating
to incentive stock options. The Committee may accelerate the exercisability of
any option at any time. Under the 2000 Plan, the exercise price of an option
is payable by the participant in cash or, at the discretion of the Committee,
in shares of Common Stock, or by any other method approved of by the Commit-
tee. The maximum number of shares of Common Stock that may be granted under
stock options to any one participant during any three calendar year period
shall be limited to 1,000,000 shares. Nonqualified stock options granted under
the 2000 Plan are intended to qualify for exemption under Section 162(m) of
the Internal Revenue Code.
Stock Appreciation Rights. The 2000 Plan authorizes the Committee to grant
awards of stock appreciation rights. A stock appreciation right may be granted
either in tandem with an option or without relationship to an option. A stock
appreciation right entitles the holder, upon exercise, to receive a payment
based on the difference between the base price of the stock appreciation right
and the fair market value of a share of Common Stock on the date of exercise,
multiplied by the number of shares as to which such stock appreciation right
will have been exercised. A stock appreciation right granted in tandem with an
option will have a base price per share equal to the per share exercise price
of the option, will be exercisable only at such time or times as the related
option is exercisable and will expire no later than the time when the related
option expires. Exercise of the option or the stock appreciation right as to a
number of shares results in the cancellation of the same number of shares un-
der the tandem right. A stock appreciation right granted without relationship
to an option will be exercisable as determined by the Committee. The base
price assigned to a stock appreciation right granted without relationship to
an option shall not be less than 100% of the fair market value of a share of
Common Stock on the date of grant. The maximum number of shares of Common
Stock that may be subject to stock appreciation rights granted to any one par-
ticipant during any three calendar year period shall be limited to 1,000,000
shares. Stock appreciation rights are payable in cash,
12
<PAGE>
restricted or unrestricted shares of Common Stock, or a combination thereof,
in the discretion of the Committee. Stock appreciation rights granted under
the 2000 Plan are intended to qualify for exemption under Section 162(m) of
the Internal Revenue Code.
Performance Awards. The 2000 Plan authorizes the Committee to grant perfor-
mance awards, which are units denominated on the date of grant either in
shares of Common Stock ("performance shares") or in specified dollar amounts
("performance units"). Performance awards are payable upon the achievement of
performance criteria established by the Committee at the beginning of the per-
formance period. At the time of grant, the Committee establishes the number of
units, the duration of the performance period or periods, the applicable per-
formance criteria and, in the case of performance units, the target unit value
or range of unit values for the performance awards. At the end of the perfor-
mance period, the Committee determines the payment to be made based on the ex-
tent to which the performance goals have been achieved. Performance awards are
payable in cash, restricted or unrestricted shares of Common Stock, phantom
stock or options, or a combination thereof, in the discretion of the Commit-
tee.
The Committee may grant performance awards that are intended to qualify for
exemption under Section 162(m) of the Internal Revenue Code, as well as per-
formance awards that are not intended to so qualify. The performance criteria
for a Section 162(m) qualified award, which may relate to AEP, any subsidiary
or any business unit, and may be measured on an absolute or relative-to-peer-
group basis, shall be limited to the following business measures:
. Financial, such as total shareholder return and earnings per share.
. Operational, such as power generation efficiency, productivity and
safety.
. Strategic, such as entering new markets and product line introductions.
The Committee may reduce the number of performance awards earned by any
participant for a performance period. The maximum amount of compensation that
may be payable in any one calendar year to any one participant designated to
receive a performance unit award intended to qualify under Section 162(m) is
$5,000,000. The maximum number of performance share units that may be earned
in any one calendar year by any one participant to qualify under Section
162(m) is 200,000 units.
Restricted Stock. The 2000 Plan authorizes the Committee to make awards of
restricted stock. An award of restricted stock represents shares of Common
Stock that are issued subject to such restrictions on transfer and on inci-
dents of ownership and such forfeiture conditions as the Committee deems ap-
propriate. The restrictions imposed upon an award of restricted stock will
lapse in accordance with the vesting requirements specified by the Committee
in the award agreement. Such vesting requirements may be based on the contin-
ued employment of the participant for a specified time period or on the at-
tainment of specified business goals or performance criteria established by
the Committee. The Committee may, in connection with an award of restricted
stock, require the payment of a specified purchase price. Subject to the
transfer restrictions and forfeiture restrictions relating to the restricted
stock award, the participant will otherwise have the rights of a shareholder
of AEP, including all voting and dividend rights, during the period of re-
striction unless the Committee determines otherwise at the time of the grant.
The Committee may grant awards of restricted stock that are intended to
qualify for exemption under Section 162(m) of the Internal Revenue Code, as
well as awards that are not intended to so qualify. An award of restricted
stock that is intended to qualify for exemption under Section 162(m) shall
have its vesting requirements limited to the performance criteria described
above under the heading Performance Awards. The maximum number of shares of
Common Stock that may be subject to awards of restricted stock intended to
qualify under Section 162(m) granted to any one participant during any calen-
dar year shall be limited to 200,000 shares.
Phantom Stock. The 2000 Plan authorizes the Committee to grant awards of
phantom stock. An award of phantom stock gives the participant the right to
receive payment at the end of a fixed vesting period based on the
13
<PAGE>
value of a share of Common Stock at the time of vesting. Phantom stock units
are subject to such restrictions and conditions to payment as the Committee
determines are appropriate. An award of phantom stock may be granted, at the
discretion of the Committee, together with an award of dividend equivalent
rights for the same number of shares covered thereby. Phantom stock awards are
payable in cash, restricted or unrestricted shares of Common Stock, options,
or a combination thereof, in the discretion of the Committee.
The same conditions and limitations applicable to restricted stock awards
are also applicable to phantom stock awards to qualify for exemption under
Section 162(m).
Dividend Equivalents. The 2000 Plan authorizes the Committee to grant
awards of dividend equivalents. Dividend equivalent awards entitle the partic-
ipant to a right to receive cash, shares of Common Stock, or other property
equal in value to dividends paid with respect to a specified number of shares
of Common Stock. Dividend equivalents may be awarded on a free-standing basis
or in connection with another award, and may be paid currently or on a de-
ferred basis. The Committee may provide at the date of grant or thereafter
that the dividend equivalent award shall be paid or distributed when accrued
or shall be deemed to have been reinvested in additional shares of Common
Stock, or other investment vehicles as the Committee may specify, provided
that dividend equivalent awards (other than free-standing dividend equivalent
awards) shall be subject to all conditions and restrictions of the underlying
awards to which they relate.
Change in Control. The Committee may provide for the effect of a "change in
control" (as defined in the 2000 Plan) upon an award granted under the 2000
Plan. Such provisions may include:
. The acceleration or extension of time periods for purposes of exercising,
vesting in, or realizing gain from an award;
. The waiver or modification of performance or other conditions related to
payment or other rights under an award;
. Providing for the cash settlement of an award; or
. Such other modification or adjustment to an award as the Committee deems
appropriate.
Term and Amendment. The 2000 Plan has no fixed expiration date. The Commit-
tee will establish expiration and exercise dates on an award-by-award basis.
However, for the purpose of awarding incentive stock options, the 2000 Plan
will expire 10 years from the date the 2000 Plan is adopted by the Board of
Directors. The Board may amend the 2000 Plan at any time, except that share-
holder approval is required for amendments that would either (i) increase the
number of shares of Common Stock reserved for issuance under the 2000 Plan or
(ii) allow the grant of options at an exercise price below fair market value
or the repricing of options.
Federal Income Tax Consequences. The following is a general description of
the federal income tax consequences to participants and AEP relating to op-
tions and other awards that may be granted under the 2000 Plan based on pres-
ent tax law. This discussion does not purport to cover all tax consequences
relating to options and other awards.
A participant will not recognize income upon the grant of a nonqualified
stock option to purchase shares of Common Stock. Upon exercise of the option,
the participant will recognize ordinary compensation income equal to the ex-
cess of the fair market value of the shares of Common Stock on the date the
option is exercised over the exercise price for such shares. AEP will be enti-
tled to a deduction equal to the amount of ordinary compensation income recog-
nized by the participant. The deduction will be allowed at the same time that
the participant recognizes the income.
A participant will not recognize income upon the grant of an incentive
stock option to purchase shares of Common Stock and will not recognize income
upon exercise of the option, provided the participant was an employee of the
AEP System at all times from the date of grant until three months prior to ex-
ercise. Where a participant who has exercised an incentive stock option sells
the shares of Common Stock acquired upon exercise more than two years after
the grant date and more than one year after exercise, capital gain or loss
will
14
<PAGE>
be recognized equal to the difference between the sales price and the exercise
price. A participant who sells such shares of Common Stock within two years
after the grant date or within one year after exercise will recognize ordinary
compensation income in an amount equal to the lesser of the difference between
(i) the exercise price and the fair market value of such shares on the date of
exercise, or (ii) the exercise price and the sales proceeds. Any remaining
gain or loss will be treated as a capital gain or loss. AEP will be entitled
to a deduction equal to the amount of ordinary compensation income recognized
by the optionee in this case. The deduction will be allowable at the same time
that the participant recognizes the income.
The current federal income tax consequences of other awards authorized un-
der the 2000 Plan are generally in accordance with the following: stock appre-
ciation rights are subject to taxation in substantially the same manner as
nonqualified stock options; restricted stock subject to a substantial risk of
forfeiture results in income recognition to the excess of the fair market
value of the shares of Common Stock over the purchase price (if any) only at
the time the restrictions lapse (unless the recipient elects to accelerate
recognition as of the date of grant); performance awards, phantom stock and
dividend equivalents are generally subject to tax at the time of payment. In
each of the foregoing cases, AEP will generally have a corresponding deduction
at the same time that the participant recognizes income.
New Plan Benefits
On January 26, 2000, under the 2000 Plan the Committee granted performance
share units for the performance period beginning January 1, 2000 and ending
December 31, 2002 and, for new participants, also granted performance share
units for two shorter performance periods. These grants of performance share
units are subject to approval of the 2000 Plan by the shareholders and the Se-
curities and Exchange Commission. If the shareholders or SEC do not approve
the 2000 Plan, these grants will be made under the predecessor AEP System Per-
formance Share Incentive Plan. Grants of other types of awards to be made un-
der the 2000 Plan will be in the discretion of the Committee and, accordingly,
are not determinable.
The following table shows for each person in the Summary Compensation Ta-
ble, and the named groups, the specified information with respect to awards
granted during 2000 under the 2000 Plan. The dollar value of benefits which
will be received by participants for their performance share awards are not
determinable in advance and, in fact, could be zero for a performance period.
Performance Share Awards in 2000
<TABLE>
<CAPTION>
Performance
Period
Number Until
of Maturation
Name Units or Payout
---- ------ -----------
<S> <C> <C>
E. L. Draper, Jr. 19,988 2000-2002
W. J. Lhota 7,157 2000-2002
D. M. Clements, Jr. 6,725 2000-2002
J. H. Vipperman 6,036 2000-2002
All Executive Officers as a Group 55,457 2000-2002
Non-Executive Officer Employee Group 71,231 2000-2002
5,981 2000-2001
2,986 2000
</TABLE>
Vote Required. Approval of this proposal requires the affirmative vote of
holders of a majority of the outstanding shares of Common Stock entitled to
vote at the meeting.
Your Board of Directors recommends a vote FOR approval of the AEP System
2000 Long-Term Incentive Plan.
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 and the AEP
2000 Long-Term Incentive Plan.
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.
15
<PAGE>
Executive Compensation
The following table shows for 1999, 1998 and 1997 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, 1999.
Summary Compensation Table
<TABLE>
<CAPTION>
Annual Long-Term
Compensation 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. -- 1999 820,000 208,280 -0- 103,218
Chairman of the board, 1998 780,000 194,376 345,906 104,941
president and chief 1997 720,000 327,744 951,132 31,620
executive officer of the
Company and the Service
Corporation; chairman and
chief executive officer of
other subsidiaries
William J. Lhota -- 1999 400,000 71,120 -0- 55,690
Executive vice president 1998 380,000 82,859 134,266 56,493
and director of the 1997 355,000 141,396 364,436 20,570
Service Corporation;
president, chief operating
officer and director of
other subsidiaries
Donald M. Clements, Jr. -- 1999 375,000 66,675 -0- 38,484
Executive vice 1998 350,000 76,317 60,047 39,040
president -- corporate
development and director
of the Service
Corporation; president and
director of AEP Resources,
Inc. (3)
James J. Markowsky -- 1999 370,000 65,786 -0- 51,047
Executive vice 1998 350,000 76,317 127,115 51,859
president -- power 1997 325,000 129,447 338,382 18,020
generation and director of
the Service Corporation;
vice president and
director of other
subsidiaries (4)
Joseph H. Vipperman -- 1999 330,000 58,674 -0- 63,006
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. Payments are made in March of the succeeding
fiscal year for performance in the year indicated. Amounts for 1999 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 1999 and page 22 for
additional information.
16
<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 and 1999, the
amounts also include split-dollar insurance. Split-dollar insurance repre-
sents the present value of the interest projected to accrue for the employ-
ee's benefit on the current year's insurance premium paid by AEP. Cumula-
tive net life insurance premiums paid are recovered by AEP at the later of
retirement or 15 years. Detail of the 1999 amounts in the All Other Compen-
sation 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.......... $ 3,462 $ 4,800 $ 3,359 $ 3,381 $ 3,762
Supplemental Savings
Plan Matching
Contributions.......... 21,138 7,200 7,891 7,719 6,138
Split-Dollar Insurance.. 68,638 33,710 27,134 29,967 47,106
Subsidiaries Directors
Fees................... 9,980 9,980 100 9,980 6,000
-------- ------- ------- ------- -------
Total All Other
Compensation........... $103,218 $55,690 $38,484 $51,047 $63,006
======== ======= ======= ======= =======
</TABLE>
(3) No 1997 compensation information is reported for Messrs. Clements and
Vipperman because they were not executive officers in these years.
(4) Dr. Markowsky resigned effective February 1, 2000.
Long-Term Incentive Plans -- Awards In 1999
Each of the awards set forth below establishes performance share unit tar-
gets, 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 perfor-
mance 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 AEP 2000 Long-Term Incentive Plan being presented for shareholder ap-
proval at the annual meeting is intended to replace the Performance Share In-
centive Plan.
The ability to earn performance share unit targets is tied to achieving
specified levels of total shareholder return ("TSR") relative to the S&P Elec-
tric 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 equiv-
alent 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.
17
<PAGE>
<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. 8,728 1999-2001 2,182 8,728 17,456
W. J. Lhota 2,980 1999-2001 745 2,980 5,960
D. M. Clements, Jr. 2,794 1999-2001 698 2,794 5,588
J. J. Markowsky 2,794 1999-2001 698 2,794 5,588
J. H. Vipperman 2,459 1999-2001 615 2,459 4,918
</TABLE>
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 Re-
tirement Plan that would be payable to employees in certain higher salary
classifications, assuming retirement at age 65 after various periods of serv-
ice.
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 $ 69,345 $ 92,460 $115,575 $138,690 $161,805 $181,755
400,000 93,345 124,460 155,575 186,690 217,805 244,405
500,000 117,345 156,460 195,575 234,690 273,805 307,055
700,000 165,345 220,460 275,575 330,690 385,805 432,355
900,000 213,345 284,460 355,575 426,690 497,805 557,655
1,200,000 285,345 380,460 475,575 570,690 665,805 745,605
</TABLE>
The amounts shown in the table are the straight life annuities payable un-
der 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 re-
tires 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 aver-
age of the 36 consecutive months of the officer's highest aggregate salary and
Senior Officer Annual 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, 1999, the number
of full years of service applicable for retirement benefit calculation pur-
poses for such officers were as follows: Dr. Draper, seven years; Mr. Lhota,
34 years; Mr. Clements, five years; Dr. Markowsky, 28 years; and Mr.
Vipperman, 37 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 en-
titlement from the Gulf States Utilities Company Trusteed Re-
18
<PAGE>
tirement Plan, a plan sponsored by their prior employer.
Eight AEP System employees (including Messrs. Lhota and Vipperman and Dr.
Markowsky) whose pensions may be adversely affected by amendments to the Re-
tirement 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
2000 of the executive officers named in the Summary Compensation Table (in-
cluding Dr. Markowsky who resigned effective February 1, 2000), 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 re-
ceipt 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 supple-
mental retirement or survivor benefit payments over a 15-year period. The
amount of supplemental retirement payments received is dependent upon the
amount deferred, age at the time the deferral election was made, and number of
years until the participant retires. The following table sets forth, for the
executive officers named in the Summary Compensation Table, the amounts of an-
nual deferrals and, assuming retirement at age 65, annual supplemental retire-
ment payments under the 1982 and 1986 programs.
<TABLE>
<CAPTION>
1982 Program 1986 Program
-------------------------------- --------------------------------
Annual Amount of Annual Amount of
Supplemental Supplemental
Annual Amount Retirement Annual 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 and Change-In-Control Agreements
Severence 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 pay-
ments and other benefits if, at any time before the second anniversary of the
merger consummation date (or, if the merger has not occurred, before the expi-
ration of the severance plan which will occur upon the termination of the
merger agreement), the officer's employment is terminated (i) by AEP without
"cause" or (ii) by the officer because of a detrimental change in responsibil-
ities or a reduction in salary or benefits. Under the severance plan, the of-
ficer 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 dis-
closure of confidential information relating to AEP.
Dr. Markowsky resigned effective February 1, 2000 and has received a lump
sum payment in accordance with the terms of the severance plan.
Change-in-Control Agreements. AEP has change-in-control agreements with Dr.
Draper and Messrs. Lhota, Clements and Vipperman. If there is a "change-in-
control" of AEP and the employee's employment is terminated by AEP
19
<PAGE>
or by the employee for reasons substantially similar to those in the severance
plan, these agreements provide for substantially the same payments and
benefits as the severance plan with the following additions:
. Three years of service credited for purposes of determining non-qualified
retirement benefits.
. Transfer to the employee of title to AEP's automobile then assigned to
the employee.
. Payment, if required, to make the employee whole for any excise tax im-
posed by Section 4999 of the Internal Revenue Code.
"Change-in-control" means:
. The acquisition by any person of the beneficial ownership of securities
representing 25% or more of AEP's voting stock.
. A change in the composition of a majority of the Board of Directors under
certain circumstances within any two-year period.
. Approval by the shareholders of the liquidation of AEP, disposition of
all or substantially all of the assets of AEP or, under certain circum-
stances, a merger of AEP with another corporation.
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 9.
The Human Resources Committee recognizes that the executive officers are
charged with managing a $20 billion, multi-state electric utility with inter-
national investments during challenging times and with addressing many diffi-
cult 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:
. To pay in a manner that motivates both short and long term performance,
focuses on meeting specified corporate goals and promotes the long term
interests of shareholders.
. To place a significant amount of compensation for senior executives at
risk, in the form of variable incentive compensation instead of fixed or
base pay with much of this risk similar to the risk experienced by other
AEP shareholders.
. To establish compensation opportunities that enhance the Company's abil-
ity to attract, retain, reward, motivate and encourage the development of
exceptionally knowledgeable, highly qualified and experienced executives.
. To target compensation levels that are reflective of current market prac-
tices in order to maintain a stable, successful management team.
In carrying out its responsibilities, the Committee utilizes a nationally
recognized independent compensation consultant to obtain information and pro-
vide recommendations relating to changing industry compensation practices and
programs. The consultant has assisted the Committee in the development of the
AEP 2000 Long-Term Incentive Plan which has been approved by the Committee and
the Board and which is being recommended to the shareholders for their ap-
proval at the annual meeting. The plan provides a list of measurements and in-
centives from which the Committee may select those which provide the most ef-
fective incentives at any given time as the Company pursues its strategies and
plans.
The Committee also considers management's responses to the impact of in-
creased competition and other significant changes in the rapid restructuring
of the electric utility in-
20
<PAGE>
dustry. It is the Committee's opinion that, in this constantly changing envi-
ronment, Dr. Draper and the senior management team continue to develop and im-
plement 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 an international energy trading organization and
the merger agreement with Central and South West Corporation. The success of
these efforts and their benefits to the Company cannot be precisely measured
in advance, but the Committee is convinced 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 share-
holder 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 suc-
cess, 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 owner-
ship targets. As of January 1, 2000, Dr. Draper has met his ownership require-
ment 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 24 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 addi-
tion, 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
certain comparably sized and complex 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. The size and com-
plexity of AEP places it above the median of its comparative group. However,
because our policy is to place more emphasis on incentive compensation, we
target executive officer base salaries somewhat below the level of our posi-
tion in the comparative group. Base salary levels in 1999 for the CEO and next
four most highly compensated executive officers of AEP named in the Summary
Compensation Table approximated the median of the comparative group consistent
with our policy to place more emphasis on incentive compensation. In estab-
lishing base salary levels in that range, the Human Resources Committee con-
siders the competitiveness of AEP's entire compensation package.
Base salaries are adjusted, as appropriate, and reviewed annually to re-
flect 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, the outside directors then determine Dr. Draper's base salary.
Annual Incentive. The primary purpose of annual incentive compensation is
to motivate senior managers, through short term (one-year) incentives and re-
wards, to maximize
21
<PAGE>
shareholder value by maximizing the Company's performance.
The Senior Officer Annual Incentive Compensation Plan (SOIP) provides a
variable, performance based portion of the executive officers' total compensa-
tion and this compensation is set forth in the Bonus column of the Summary
Compensation Table. SOIP participants are assigned an annual target award ex-
pressed as a percentage of annual salary. For 1999, the target awards for Dr.
Draper and the other executive officers named in the compensation table were
50% and 35%, respectively. Actual awards will vary from 0-200% of the target
award based on performance.
SOIP awards are 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 measured relative to that of other large utilities.
For 1999, AEP performance merited an award of 50.8%. This percentage is an
estimate but should not change significantly. Final awards will be determined
when audited results are available for AEP and the comparative companies.
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 Com-
pany, although no stock is actually purchased. Dividend equivalents are cred-
ited during the deferral period.
Long-Term Incentive. The primary purpose of longer term, equity based, in-
centive compensation is to motivate senior managers to maximize shareholder
value by linking a portion of their compensation directly to shareholder re-
turn.
The Performance Share Incentive Plan (PSIP) annually establishes perfor-
mance 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 Jan-
uary 1999, the Committee established targets for Dr. Draper and the other ex-
ecutive officers named in the Summary Compensation Table equivalent to 50% and
35%, respectively, of their then base salaries. The target number of perfor-
mance share units has been determined after an evaluation of long term incen-
tive opportunities provided by the electric utility companies in AEP's compar-
ative group. 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 1999. AEP's to-
tal shareholder return for 1997-1999 ranked twenty-fifth relative to the S&P
peer utilities and, as a result, none of the performance share unit targets
originally established for that period (and dividend credits) were earned. The
associated awards for 1998 and 1997 are listed in the Summary Compensation Ta-
ble.
Payments of earned awards under the PSIP are deferred in the form of re-
stricted stock units (equivalent to shares of AEP Common Stock). Such PSIP de-
ferrals continue until termination of employment or, if so elected by the re-
cipient, 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 addi-
tional restricted stock units. The PSIP is further described on page 17.
Tax Policy
The Committee has considered the impact of Section 162(m) of the Internal
Revenue
22
<PAGE>
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 other four executive officers named in the Summary Compensation Table. It
is the Committee's policy, when consistent with sound executive compensation
principles and the needs of the Company, to qualify compensation for deduct-
ibility 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 per-
formance-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 1999 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 1999 in excess of the deduction limit and all such compensation was fully
deductible. 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
[GRAPH]
AEP S&P 500 S&P ELECTRIC
1994 100.00 100.00 100.00
1995 131.97 137.58 130.98
1996 141.84 169.17 130.94
1997 188.25 225.61 165.76
1998 180.53 290.47 193.01
1999 131.14 351.41 161.95
Assumes $100 Invested on Jan- * Total Return Assumes
uary 1, 1995 in AEP Common Reinvestment of Divi-
Stock, S&P 500 Index and S&P dends
Electric Utility Index ** Fiscal Year Ending De-
cember 31
The total return performance shown on the graph above is not necessarily
indicative of future performance.
23
<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, 2000 for all directors as of the date of
this proxy statement, all nominees to the Board of Directors, each of the per-
sons 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>
E. R. Brooks................................ -0-(b) -0- -0-
D. M. Carlton............................... -0-(b) -0- -0-
D. M. Clements, Jr.......................... 1,424(c) 13,741 15,165
J. P. DesBarres............................. 5,000(d) 998 5,998
E. L. Draper, Jr............................ 8,670(c)(d) 89,257 97,927
R. M. Duncan................................ 2,304 3,554 5,858
R. W. Fri................................... 1,000 1,681 2,681
W. R. Howell................................ -0-(b) -0- -0-
L. A. Hudson, Jr............................ 1,853(e) 3,554 5,407
L. J. Kujawa................................ 1,300 2,623 3,923
W. J. Lhota................................. 17,364(c)(d)(f) 15,174 32,538
J. J. Markowsky............................. 2,871(c)(e) 13,923 16,794
J. L. Powell................................ -0-(b) -0- -0-
R. L. Sandor................................ -0-(b) -0- -0-
T. V. Shockley, III......................... -0-(b) -0- -0-
D. G. Smith................................. 2,500 2,051 4,551
L. G. Stuntz................................ 1,500(d) 3,239 4,739
K. D. Sullivan.............................. -0- 1,889 1,889
M. Tanenbaum................................ 1,607 3,508 5,115
J. H. Vipperman............................. 11,569(c)(d)(f) 4,549 16,118
All directors, nominees and executive
officers as a group (22 persons)........... 154,134(f)(g) 173,799 327,933
</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) These nominees, as directors and/or officers of CSW, hold shares of CSW
Common Stock which, upon the merger with AEP, will be exchanged for 0.60 of
a share of AEP Common Stock for each share of CSW Common Stock owned by
them.
(c) Includes the following numbers of share equivalents held in the AEP Employ-
ees 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, 1,424: Dr. Draper, 3,449; Mr. Lhota, 15,184; Dr. Markowsky,
2,814; Mr. Vipperman, 10,790; and all executive officers, 38,449.
(d) Includes the following numbers of shares held in joint tenancy with a fam-
ily member: Mr. DesBarres, 5,000; Dr. Draper, 5,221; Mr. Lhota, 2,180; Ms.
Stuntz, 300; Mr. Vipperman, 71; and an executive officer, 2,055.
(e) Includes the following numbers of shares held by family members over which
beneficial ownership is disclaimed: Dr. Hudson, 750; Dr. Markowsky, 21; and
an executive officer, 2,560.
(f) 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 direc-
tors and executive officers as a group includes these shares.
(g) Represents less than 1% of the total number of shares outstanding.
24
<PAGE>
Share Ownership of Certain Beneficial Owners
Set forth below are the only persons or groups known to AEP as of December 31,
1999, 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>
Barrow, Hanley,...................................... 10,385,000(a) 5.4%
Mewhinney & Strauss, Inc.
One McKinney Plaza 3232 McKinney Avenue 15th Floor
Dallas, TX 75204
Sanford C............................................ 16,984,332(b) 8.8%
Bernstein & Co., Inc.
767 Fifth Avenue
New York, NY 10153
Capital Research and................................. 13,495,000(c) 7.0%
Management Company
333 South Hope St. 55th Floor
Los Angeles,
CA 90071
Vanguard Windsor..................................... 10,090,300(d) 5.2%
Funds-Vanguard Windsor II Fund
100 Vanguard Blvd.
Malvern, PA 19355
</TABLE>
- --------
(a) Based on the Schedule 13G filed with the SEC, Barrow, Hanley, Mewhinney &
Strauss, Inc., an investment adviser, reported that it has sole voting
power for 139,300 shares, shared voting power for 10,245,700 shares, and
sole dispositive power for 10,385,000 shares.
(b) Based on the Schedule 13G, Sanford C. Bernstein & Co., Inc., an investment
adviser, reported that it has sole voting power for 10,335,142 shares,
shared voting power for 1,420,506 shares, and sole dispositive power for
16,984,332 shares.
(c) Based on the Schedule 13G, Capital Research and Management Company, an in-
vestment adviser, reported that it has sole dispositive power for
13,495,000 shares.
Capital Research disclaims beneficial ownership.
(d) Based on the Schedule 13G, Vanguard Windsor Funds, an investment company,
reported that it has sole voting and shared dispositive power for
10,090,300 shares.
Shareholder Proposals
To be included in AEP's proxy statement and form of proxy for the 2001 annual
meeting of shareholders, any proposal which a shareholder intends to present
at such meeting must be received by AEP, attention: Susan Tomasky, Secretary,
at AEP's office at 1 Riverside Plaza, Columbus, Ohio 43215 by November 10,
2000.
For any proposal intended to be presented by a shareholder without inclu-
sion in AEP's proxy statement and form of proxy for the 2001 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 5, 2001. 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 so-
licited principally by mail, but some telephone, telegraph or personal solici-
tations 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 re-
quest brokers, banks and other custodians or fiduciaries holding shares in
their names or in the names of nominees to forward copies of the proxy-solic-
iting 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 pre-
scribed by the New York Stock Exchange. Morrow & Co., Inc. will assist in the
solicitation of proxies by AEP for a fee of $12,000, plus reasonable out-of-
pocket expenses.
25
<PAGE>
EXHIBIT A
AMERICAN ELECTRIC POWER SYSTEM
2000 LONG-TERM INCENTIVE PLAN
Table of Contents
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Section Page
<S> <C>
1. Purpose of the Plan.................................................... A-1
2. Definitions............................................................ A-1
3. Shares of Common Stock Subject to the Plan............................. A-2
4. Administration of the Plan............................................. A-3
5. Eligibility and Awards................................................. A-4
6. Stock Options.......................................................... A-4
7. Stock Appreciation Rights.............................................. A-5
8. Restricted Stock....................................................... A-5
9. Performance Awards..................................................... A-6
10. Phantom Stock.......................................................... A-7
11. Dividend Equivalents................................................... A-8
12. Change in Control...................................................... A-8
13. Award Agreements....................................................... A-9
14. General Provisions..................................................... A-9
15. Effective Date, Termination and Amendment.............................. A-11
</TABLE>
<PAGE>
American Electric Power System 2000 Long-Term Incentive Plan
1. Purpose of the Plan
The purpose of the American Electric Power System 2000 Long-Term Incentive
Plan is to promote the interests of AEP and its shareholders by strengthening
AEP's ability to attract, motivate and retain employees and directors of AEP
and its Subsidiaries upon whose judgment, initiative and efforts the financial
success and growth of the business of AEP largely depend, to align further the
interests of AEP's management with the shareholders, and to provide an addi-
tional incentive for employees and directors through stock ownership and other
rights that promote and recognize the financial success and growth of AEP.
2. Definitions
Wherever the following capitalized terms are used in this Plan they shall
have the meanings specified below:
(a) "AEP" means American Electric Power Company, Inc., a New York corporation,
and any successor thereto.
(b) "AEP-CSW Merger" means the consummation of the transactions contemplated
in the Agreement and Plan of Merger by and among American Electric Power,
Inc., Augusta Acquisition Corporation and Central and South West Corpora-
tion dated as of December 21, 1997, as amended.
(c) "Award" means an award of an Option, Restricted Stock, Stock Appreciation
Right, Performance Award, Phantom Stock or Dividend Equivalent granted un-
der the Plan.
(d) "Award Agreement" means an agreement entered into between AEP and a Par-
ticipant setting forth the terms and conditions of an Award granted to a
Participant.
(e) "Board" means the Board of Directors of AEP.
(f) "Change in Control" shall have the meaning specified in Section 12 hereof.
(g) "Code" means the Internal Revenue Code of 1986, as amended.
(h) "Committee" means the Human Resources Committee of the Board, or such
other committee or subcommittee of the Board appointed by the Board to ad-
minister the Plan from time to time.
(i) "Common Stock" means the common stock of AEP, $6.50 par value.
(j) "Date of Grant" means the date on which the Committee makes an Award under
the Plan, or such later date as the Committee may specify that the Award
becomes effective.
(k) "Effective Date" means the Effective Date of this Plan, as defined in Sec-
tion 15.1 hereof.
(l) "Dividend Equivalent" means an Award under Section 11 hereof entitling the
Participant to receive payments with respect to dividends declared on the
Common Stock.
(m) "Eligible Person" means any person who is an Employee or an Independent
Director.
(n) "Employee" means any person who is an employee of AEP or any Subsidiary;
provided, however, that with respect to Incentive Stock Options, "Employ-
ee" means any person who is considered an employee of AEP or any Subsidi-
ary for purposes of Section 424 of the Code.
(o) "Fair Market Value" means, as of any applicable date, the closing price
per share of the Common Stock as quoted in the New York Stock Exchange--
Composite Transactions listing in The Wall Street Journal (or such other
reliable publication as the Committee, in its discretion, may determine to
rely upon) for the date as of which Fair Market Value is to be determined.
If there are no sales on such date, then Fair Market Value shall be the
closing price per share of the Common Stock as so quoted on the nearest
date before the date as of which Fair Market Value is to be determined on
which there are sales. If the Common Stock is not listed on the New York
Stock Exchange on the date as of which Fair Mar-
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ket Value is to be determined, the Committee shall determine in good faith
the Fair Market Value in whatever manner it considers appropriate. Fair
Market Value shall be determined without regard to any restriction other
than a restriction which, by its terms, will never lapse.
(p) "Independent Director" means a member of the Board who is not an Employee.
(q) "Incentive Stock Option" means an option to purchase Common Stock that is
intended to qualify as an incentive stock option under Section 422 of the
Code, or any successor provision thereto.
(r) "Nonqualified Stock Option" means an option to purchase Common Stock that
is not an Incentive Stock Option.
(s) "Option" means an Incentive Stock Option or a Nonqualified Stock Option
granted under Section 6 hereof.
(t) "Participant" means any Eligible Person who holds an outstanding Award un-
der the Plan.
(u) "Phantom Stock" means an Award under Section 10 hereof entitling a Partic-
ipant to a payment based on a measure of value expressed as a share of
Common Stock. No stock certificates shall be issued with respect to such
Phantom Stock Units, but AEP shall maintain a bookkeeping account in the
name of the Participant to which the Phantom Stock Units shall relate.
(v) "Plan" means the American Electric Power System 2000 Long-Term Incentive
Plan as set forth herein, as it may be amended from time to time.
(w) "Performance Award" means an Award made under Section 9 hereof entitling a
Participant to a payment based on the Fair Market Value of Common Stock (a
"Performance Share") or based on specified dollar units (a "Performance
Unit") at the end of a performance period if certain conditions estab-
lished by the Committee are satisfied.
(x) "Restricted Stock" means an Award under Section 8 hereof entitling a Par-
ticipant to shares of Common Stock that are nontransferable and subject to
forfeiture until specific conditions established by the Committee are sat-
isfied.
(y) "Section 162(m)" means Section 162(m) of the Code and the Treasury Regula-
tions thereunder.
(z) "Section 162(m) Participant" means any Participant who, in the sole judg-
ment of the Committee, could be treated as a "covered employee" under Sec-
tion 162(m) at the time income may be recognized by such Participant in
connection with an Award that is intended to qualify for exemption under
Section 162(m).
(aa) "Stock Appreciation Right" or "SAR" means an Award under Section 7 hereof
entitling a Participant to receive an amount, representing the difference
between the base price per share of the right and the Fair Market Value
of a share of Common Stock on the date of exercise.
(bb) "Subsidiary" means any corporation (other than AEP) in an unbroken chain
of corporations beginning with AEP if, at the time of granting an Award,
each of the corporations, other than the last corporation in the unbroken
chain, owns stock possessing 50 percent or more of the total combined
voting power of all classes of stock in one of the other corporations in
such chain.
3. Shares of Common Stock Subject to the Plan
3.1. Calculation of Number of Shares Available. Subject to the following
provisions of this Section 3, the aggregate number of shares of Common Stock
that may be issued pursuant to all Awards under the Plan is 9,500,000 shares
of Common Stock.
If any share of Common Stock that is the subject of an Award is not issued
and ceases to be issuable for any reason, or is forfeited, cancelled or re-
turned to AEP for failure to satisfy vesting requirements or upon the occur-
rence of other forfeiture events, such share of Common Stock will no longer be
charged against the foregoing maximum share limitations and may
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again be made subject to Awards under the Plan pursuant to such limitations.
3.2. Accounting for Awards. For purposes of this Section 3, if an Award is
denominated in shares of Common Stock, the number of shares covered by such
Award, or to which such Award relates, shall be counted on the Date of Grant
of such Award against the aggregate number of shares available for granting
Awards under the Plan; provided, however, that Awards that operate in tandem
with (whether granted simultaneously with or at a different time from) other
Awards may be counted or not counted under procedures adopted by the Committee
in order to avoid double counting.
3.3. Source of Shares of Common Stock Deliverable Under Awards. The shares
of Common Stock to be delivered under the Plan may be authorized but unissued
shares, reacquired shares, shares acquired on the open market specifically for
distribution under the Plan, or any combination thereof.
3.4. Adjustments. If there shall occur any recapitalization, reclassifica-
tion, stock dividend, stock split, reverse stock split or other distribution
with respect to the shares of Common Stock, or any similar corporate transac-
tion or event in respect of the Common Stock such as the AEP-CSW Merger, then
the Committee shall, in the manner and to the extent that it deems appropriate
and equitable to the Participants and consistent with the terms of this Plan,
cause a proportionate adjustment to be made in (a) the maximum numbers and
kind of shares provided in Section 3.1 hereof, (b) the maximum numbers and
kind of shares set forth in Sections 6.1, 7.1, 8.2 and 9.4 hereof, (c) the
number and kind of shares of Common Stock, share units, or other rights sub-
ject to the then-outstanding Awards, (d) the price for each share or unit or
other right subject to then outstanding Awards without change in the aggregate
purchase price or value as to which such Awards remain exercisable or subject
to restrictions, (e) the performance targets or goals appropriate to any out-
standing Performance Awards (subject to such limitations as appropriate for
Awards intended to qualify for exemption under Section 162(m)) or (f) any
other terms of an Award that are affected by the event. Notwithstanding the
foregoing, in the case of Incentive Stock Options, any such adjustments shall
be made in a manner consistent with the requirements of Section 424(a) of the
Code.
4. Administration of the Plan
4.1. Committee Members. Except as provided in Section 4.4 hereof, the Com-
mittee will administer the Plan. The Committee may exercise such powers and
authority as may be necessary or appropriate for the Committee to carry out
its functions as described in the Plan. No member of the Committee will be li-
able for any action or determination made in good faith by the Committee with
respect to the Plan or any Award under it.
4.2. Discretionary Authority. Subject to the express limitations of the
Plan, the Committee has authority in its discretion to determine the Eligible
Persons to whom, and the time or times at which, Awards may be granted, the
number of shares, units or other rights subject to each Award, the exercise,
base or purchase price of an Award (if any), the time or times at which an
Award will become vested, exercisable or payable, the performance criteria,
performance goals and other conditions of an Award, and the duration of the
Award. The Committee also has discretionary authority to interpret the Plan,
to make all factual determinations under the Plan, and to determine the terms
and provisions of the respective Award Agreements and to make all other deter-
minations necessary or advisable for Plan administration. The Committee has
authority to prescribe, amend, and rescind rules and regulations relating to
the Plan. All interpretations, determinations, and actions by the Committee
will be final, conclusive, and binding upon all parties.
4.3. Changes to Awards. The Committee shall have the authority to effect,
at any time and from time to time, with the consent of the affected Partici-
pants, (a) the cancellation of any or all outstanding Awards and the grant in
substitution therefor of new Awards covering the same or different numbers of
shares of Common Stock and having an exercise or base price which may be the
same as or different than the exercise or base price of the cancelled Awards
or (b) the amendment of the terms of
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any and all outstanding Awards; provided, however, that the Committee shall
not have the authority to reduce the exercise or base price of an Award by
amendment or cancellation and substitution of an existing Award without the
approval of AEP's shareholders. The Committee may in its discretion accelerate
the vesting or exercisability of an Award at any time or on the basis of any
specified event.
4.4. Delegation of Authority. As permitted by law, the Committee may dele-
gate its authority as identified hereunder; provided, however, that the Com-
mittee may not delegate certain of its responsibilities hereunder if such del-
egation may jeopardize compliance with the "outside directors" provision of
Section 162(m).
4.5 Awards to Independent Directors. The Independent Directors of the Board
shall approve an Award to an Independent Director under the Plan. With respect
to Awards to Independent Directors, all rights, powers and authorities vested
in the Committee under the Plan shall instead be exercised by the Independent
Directors of the Board, and all provisions of the Plan relating to the Commit-
tee shall be interpreted in a manner consistent with the foregoing by treating
any such reference as a reference to the Independent Directors of the Board
for such purpose.
5. Eligibility and Awards
All Eligible Persons are eligible to be designated by the Committee to re-
ceive an Award under the Plan. The Committee has authority, in its sole dis-
cretion, to determine and designate from time to time those Eligible Persons
who are to be granted Awards, the types of Awards to be granted and the number
of shares or units subject to the Awards that are granted under the Plan. Each
Award will be evidenced by an Award Agreement as described in Section 13
hereof between AEP and the Participant that shall include the terms and condi-
tions consistent with the Plan as the Committee may determine.
6. Stock Options
6.1. Grant of Option. An Option may be granted to any Eligible Person se-
lected by the Committee; provided, however, that only Employees shall be eli-
gible for Awards of Incentive Stock Options. Each Option shall be designated,
at the discretion of the Committee, as an Incentive Stock Option or a Nonqual-
ified Stock Option. The maximum number of shares of Common Stock that may be
granted under Options to any one Participant during any three calendar year
period shall be limited to 1,000,000 shares (subject to adjustment as provided
in Section 3.4 hereof).
6.2. Exercise Price. The exercise price of the Option shall be determined
by the Committee; provided, however, that the exercise price per share of an
Option shall not be less than 100 percent of the Fair Market Value per share
of the Common Stock on the Date of Grant. Notwithstanding the foregoing, in
the event that options are assumed in a transaction which would satisfy the
conditions of Section 424 of the Code (whether or not such section would oth-
erwise be applicable), the Committee may grant Options with an exercise price
per share less than 100 percent of the Fair Market Value on the date of grant.
6.3. Vesting; Term of Option. The Committee, in its sole discretion, shall
prescribe in the Award Agreement the time or times at which, or the conditions
upon which, an Option or portion thereof shall become vested and exercisable,
and may accelerate the exercisability of any Option at any time.
6.4. Option Exercise; Withholding. Subject to such terms and conditions as
shall be specified in an Award Agreement, an Option may be exercised in whole
or in part at any time during the term thereof by written notice to AEP to-
gether with payment of the aggregate exercise price therefor. Payment of the
exercise price shall be made (a) in cash or by cash equivalent, (b) at the
discretion of the Committee, in shares of Common Stock acceptable to the Com-
mittee, valued at the Fair Market Value of such shares on the date of exer-
cise, (c) at the discretion of the Committee, by a delivery of a notice that
the Participant has placed a market sell order (or similar instruction) with a
third party with respect to shares of Common Stock then issuable upon exercise
of the Option, and that the third party has been directed to pay a sufficient
portion of the net proceeds of the sale to
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AEP in satisfaction of the Option exercise price or (d) at the discretion of
the Committee, by a combination of the methods described above or such other
method as may be approved by the Committee. In addition to and at the time of
payment of the exercise price, the Participant shall pay to AEP the full
amount of any and all applicable income tax and employment tax amounts re-
quired to be withheld in connection with such exercise, payable under one or
more of the methods described above for the payment of the exercise price of
the Options as may be approved by the Committee.
6.5. Additional Rules for Incentive Stock Options. The terms of any Incen-
tive Stock Option granted under the Plan shall comply in all respects with the
provisions of Section 422 of the Code, or any successor provision thereto, and
any regulations promulgated thereunder.
7. Stock Appreciation Rights
7.1. Grant of SARs. A Stock Appreciation Right granted to a Participant is
an Award in the form of a right to receive, upon surrender of the right, but
without other payment, an amount based on appreciation in the Fair Market
Value of the Common Stock over a base price established for the Award, exer-
cisable at such time or times and upon conditions as may be approved by the
Committee. The maximum number of shares of Common Stock that may be subject to
SARs granted to any one Participant during any three calendar year period
shall be limited to 1,000,000 shares (subject to adjustment as provided in
Section 3.4 hereof).
7.2. Tandem SARs. A Stock Appreciation Right may be granted in connection
with an Option, either at the time of grant or at any time thereafter during
the term of the Option. An SAR granted in connection with an Option will enti-
tle the holder, upon exercise, to surrender such Option or any portion thereof
to the extent unexercised, with respect to the number of shares as to which
such SAR is exercised, and to receive payment of an amount computed as de-
scribed in Section 7.4 hereof. Such Option will, to the extent and when sur-
rendered, cease to be exercisable. An SAR granted in connection with an Option
hereunder will have a base price per share equal to the per share exercise
price of the Option, will be exercisable at such time or times, and only to
the extent, that a related Option is exercisable, and will expire no later
than the related Option expires.
7.3. Freestanding SARs. A Stock Appreciation Right may be granted without
relationship to an Option and, in such case, will be exercisable as determined
by the Committee. The base price of an SAR granted without relationship to an
Option shall be determined by the Committee in its sole discretion; provided,
however, that the base price per share of a freestanding SAR shall not be less
than 100 percent of the Fair Market Value of the Common Stock on the Date of
Grant.
7.4. Payment of SARs. An SAR will entitle the holder, upon exercise of the
SAR, to receive payment of an amount determined by multiplying: (i) the excess
of the Fair Market Value of a share of Common Stock on the date of exercise of
the SAR over the base price of such SAR, by (ii) the number of shares as to
which such SAR will have been exercised. Payment of the amount determined un-
der the foregoing may be made, in the discretion of the Committee, in cash, in
Restricted Stock or shares of unrestricted Common Stock (both valued at their
Fair Market Value on the date of exercise), or a combination thereof.
8. Restricted Stock
8.1. Grants of Restricted Stock. An Award of Restricted Stock to a Partici-
pant represents shares of Common Stock that are issued subject to such re-
strictions on transfer and other incidents of ownership and such forfeiture
conditions as the Committee may determine. The Committee may, in connection
with an Award of Restricted Stock, require the payment of a specified purchase
price. The Committee may grant and designate Awards of Restricted Stock that
are intended to qualify for exemption under Section 162(m), as well as Awards
of Restricted Stock that are not intended to so qualify.
8.2. Vesting Requirements. The restrictions imposed on an Award of Re-
stricted Stock shall lapse in accordance with the vesting requirements speci-
fied by the Committee in the Award Agreement. Such vesting requirements may be
based on the continued employment of
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the Participant with AEP or its Subsidiaries for a specified time period or pe-
riods, provided that any such restriction shall not be scheduled to lapse in
its entirety earlier than the first anniversary of the Date of Grant. Such
vesting requirements may also be based on the attainment of specified business
goals or measures established by the Committee in its sole discretion. In the
case of any Award of Restricted Stock that is intended to qualify for exemption
under Section 162(m), the vesting requirements shall be limited to the perfor-
mance criteria identified in Section 9.3 below, and the terms of the Award
shall otherwise comply with the Section 162(m) requirements described in Sec-
tion 9.4 hereof; provided, however, that the maximum number of shares of Common
Stock that may be subject to an Award of Restricted Stock granted to a Section
162(m) Participant during any one calendar year shall be separately limited to
200,000 shares (subject to adjustment as provided in Section 3.4 hereof).
8.3. Restrictions. Shares of Restricted Stock may not be transferred, as-
signed or subject to any encumbrance, pledge or charge until all applicable re-
strictions are removed or expire or unless otherwise allowed by the Committee.
The Committee may require the Participant to enter into an escrow agreement
providing that the certificates representing Restricted Stock granted or sold
pursuant to the Plan will remain in the physical custody of an escrow holder
until all restrictions are removed or expire. Failure to satisfy any applicable
restrictions shall result in the subject shares of Restricted Stock being for-
feited and returned to AEP, with any purchase price paid by the Participant to
be refunded, unless otherwise provided by the Committee. The Committee may re-
quire that certificates representing Restricted Stock granted under the Plan
bear a legend making appropriate reference to the restrictions imposed.
8.4. Rights as Shareholder. Subject to the foregoing provisions of this Sec-
tion 8 and the applicable Award Agreement, the Participant will have all rights
of a shareholder with respect to shares of Restricted Stock granted to the Par-
ticipant, including the right to vote the shares and receive all dividends and
other distributions paid or made with respect thereto, unless the Committee de-
termines otherwise at the time the Restricted Stock is granted, as set forth in
the Award Agreement.
8.5. Section 83(b) Election. The Committee may provide in an Award Agreement
that the Award of Restricted Stock is conditioned upon the Participant re-
fraining from making an election with respect to the Award under Section 83(b)
of the Code. Irrespective of whether an Award is so conditioned, if a Partici-
pant makes an election pursuant to Section 83(b) of the Code with respect to an
Award of Restricted Stock, the Participant shall be required to promptly file a
copy of such election with AEP.
9. Performance Awards
9.1. Grant of Performance Awards. The Committee may grant Performance
Awards under the Plan, which shall be represented by units denominated on the
Date of Grant either in shares of Common Stock (Performance Shares) or in spec-
ified dollar amounts (Performance Units). The Committee may grant and designate
Performance Awards that are intended to qualify for exemption under Section
162(m), as well as Performance Awards that are not intended to so qualify. At
the time a Performance Award is granted, the Committee shall determine, in its
sole discretion, one or more performance periods and performance goals to be
achieved during the applicable performance periods, as well as such other re-
strictions and conditions as the Committee deems appropriate. In the case of
Performance Units, the Committee shall also determine a target unit value or a
range of unit values for each Award. The performance goals applicable to a Per-
formance Award grant may be subject to such later revisions as the Committee
shall deem appropriate to reflect significant unforeseen events such as changes
in law, accounting practices or unusual or nonrecurring items or occurrences.
Any such adjustments shall be subject to such limitations as the Committee
deems appropriate in the case of a Performance Award granted to a Section
162(m) Participant that is intended to qualify for exemption under Section
162(m).
9.2. Payment of Performance Awards. At the end of the performance period,
the Committee shall determine the extent to which performance goals have been
attained or a degree of
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achievement between minimum and maximum levels in order to establish the level
of payment to be made, if any. The Committee shall determine if payment is to
be made in cash, Restricted Stock, shares of unrestricted Common Stock, Op-
tions or Phantom Stock, or a combination thereof. For any cash conversion to
or from Performance Shares or Units, Phantom Stock units or shares of Common
Stock, payment shall be calculated on the basis of the average of the Fair
Market Value of the Common Stock for the last 20 trading days prior to the
payment date.
9.3. Performance Criteria. The performance criteria upon which the payment
or vesting of a Performance Award intended to qualify for exemption under Sec-
tion 162(m) may be based shall be limited to the following business measures,
which may be applied with respect to AEP, any Subsidiary or any business unit,
and which may be measured on an absolute or relative-to-peer-group basis: (a)
financial, such as total shareholder return and earnings per share, (b) opera-
tional, such as power generation efficiency, productivity and safety, and (c)
strategic, such as entering new markets and product line introductions. In any
event, the Committee may, at its discretion, reduce the number of Performance
Awards earned by any Participant for a performance period. In the case of Per-
formance Awards that are not intended to qualify for exemption under Section
162(m), the Committee shall designate performance criteria from among the
foregoing or such other business criteria as it shall determine in its sole
discretion.
9.4. Section 162(m) Requirements. In the case of a Performance Award
granted to a Section 162(m) Participant that is intended to comply with the
requirements for exemption under Section 162(m), the Committee shall make all
determinations necessary to establish a Performance Award within 90 days of
the beginning of the performance period (or such other time period required
under Section 162(m)), including, without limitation, the designation of the
Section 162(m) Participants to whom Performance Awards are made, the perfor-
mance criteria or criterion applicable to the Award and the performance goals
that relate to such criteria, and the dollar amounts or number of shares of
Common Stock or Phantom Stock units payable upon achieving the applicable per-
formance goals. As and to the extent required by Section 162(m), the terms of
a Performance Award granted to a Section 162(m) Participant must state, in
terms of an objective formula or standard, the method of computing the amount
of compensation payable to the Section 162(m) Participant, and must preclude
discretion to increase the amount of compensation payable that would otherwise
be due under the terms of the Award. The maximum amount of compensation that
may be payable to a Section 162(m) Participant during any one calendar year
under a Performance Unit Award shall be $5,000,000. The maximum number of Per-
formance Share units that may be earned by a Section 162(m) Participant during
any one calendar year shall be 200,000 (subject to adjustment as provided in
Section 3.4 hereof).
10. Phantom Stock
10.1. Grant of Phantom Stock. Phantom Stock is an Award to a Participant
of a number of hypothetical share units with respect to shares of Common
Stock, with an initial value based on the average of the Fair Market Value of
the Common Stock for the last 20 trading days prior to the Date of Grant.
Phantom Stock shall be subject to such restrictions and conditions as the Com-
mittee shall determine. Sections 8.1 and 8.2 shall apply to Awards of Phantom
Stock units in similar manner as they apply to shares of Restricted Stock, as
interpreted by the Committee, with the limitation in Section 8.2 on the number
of shares of Restricted Stock which may be granted applicable separately to
Phantom Stock units. An Award of Phantom Stock may be granted, at the discre-
tion of the Committee, together with an Award of Dividend Equivalent rights
for the same number of shares covered thereby.
10.2. Payment of Phantom Stock. Upon the vesting date applicable to Phan-
tom Stock granted to a Participant, an amount equal to one share of Common
Stock upon such date shall be paid with respect to such Phantom Stock unit
granted to the Participant. Payment may be made, at the discretion of the Com-
mittee, in cash, Restricted Stock, shares of unrestricted Common Stock, Op-
tions, or a combination thereof. Cash payments of Phantom Stock units shall be
calculated on the basis of the av-
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erage of the Fair Market Value of the Common Stock for the last 20 trading
days prior to the payment date.
11. Dividend Equivalents
A Dividend Equivalent granted to a Participant is an Award in the form of a
right to receive cash, shares of Common Stock, or other property equal in
value to dividends paid with respect to a specific number of shares of Common
Stock. Dividend Equivalents may be awarded on a free-standing basis or in con-
nection with another Award, and may be paid currently or on a deferred basis.
The Committee may provide at the Date of Grant or thereafter that the Dividend
Equivalent shall be paid or distributed when accrued or shall be deemed to
have been reinvested in additional shares of Common Stock or such other in-
vestment vehicles as the Committee may specify; provided, however, that Divi-
dend Equivalents (other than free-standing Dividend Equivalents) shall be sub-
ject to all conditions and restrictions of the underlying Awards to which they
relate.
12. Change in Control
12.1. Effect of Change in Control. The Committee may, in an Award Agree-
ment, provide for the effect of a Change in Control on an Award. Such provi-
sions may include any one or more of the following: (a) the acceleration or
extension of time periods for purposes of exercising, vesting in, or realizing
gain from any Award, (b) the waiver or modification of performance or other
conditions related to the payment or other rights under an Award; (c) provi-
sion for the cash settlement of an Award for an equivalent cash value, as de-
termined by the Committee, or (d) such other modification or adjustment to an
Award as the Committee deems appropriate to maintain and protect the rights
and interests of Participants upon or following a Change in Control.
12.2. Definition of Change in Control. For purposes hereof, a "Change in
Control" shall be deemed to have occurred if:
(a) any "person" or "group" (as such terms are used in Sections 13(d) and
14(d) of the Securities Exchange Act of 1934 ("Exchange Act")), other than
any company owned, directly or indirectly, by the shareholders of AEP in
substantially the same proportions as their ownership of shares of Common
Stock or a trustee or other fiduciary holding securities under an employee
benefit plan of AEP, becomes the "beneficial owner" (as defined in Rule
13d-3 under the Exchange Act), directly or indirectly, of more than 25
percent of the then outstanding voting stock of AEP;
(b) during any period of two consecutive years, individuals who at the begin-
ning of such period constitute the Board, together with any new directors
(other than a director nominated by a person (i) who has entered into an
agreement with AEP to effect a transaction described in Section 12.2(a),
(c) or (d) hereof or (ii) who publicly announces an intention to take or
consider taking actions (including, but not limited to, an actual or
threatened proxy contest) which if consummated would constitute a Change
in Control) whose election or nomination for election was approved by a
vote of at least two-thirds of the directors then still in office who were
either directors at the beginning of the period or whose election or nomi-
nation for election was previously so approved, cease for any reason (ex-
cept for death, disability or voluntary retirement) to constitute at least
a majority of the Board;
(c) AEP consummates a merger or consolidation with any other entity, other
than a merger or consolidation which would result in the voting securities
of AEP outstanding immediately prior thereto continuing to represent (ei-
ther by remaining outstanding or by being converted into voting securities
of the surviving entity) at least 50 percent of the total voting power
represented by the voting securities of AEP or such surviving entity out-
standing immediately after such merger or consolidation; or
(d) the shareholders of AEP approve a plan of complete liquidation of AEP, or
an agreement for the sale or disposition by AEP (in one transaction or a
series of transactions) of all or substantially all of AEP's assets.
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Notwithstanding the foregoing, a Change in Control shall not be deemed to
occur as a result of the AEP-CSW Merger, nor thereafter as a result of any
event in (a) or (c) above, if directors who were members of the Board prior to
such event continue to constitute a majority of the Board after such event.
13. Award Agreements
13.1. Form of Agreement. Each Award under this Plan shall be evidenced by
an Award Agreement in a form approved by the Committee setting forth the num-
ber of shares of Common Stock, units or other rights (as applicable) subject
to the Award, the exercise, base or purchase price (if any) of the Award, the
time or times at which an Award will become vested, exercisable or payable,
the duration of the Award and, in the case of Performance Awards, the applica-
ble performance criteria and goals. The Award Agreement shall also set forth
other material terms and conditions applicable to the Award as determined by
the Committee consistent with the limitations of this Plan. Award Agreements
evidencing Awards intended to qualify for exemption under Section 162(m) may
be designated as such and shall contain such terms and conditions as may be
necessary to meet the applicable requirements of Section 162(m). Award Agree-
ments evidencing Incentive Stock Options shall contain such terms and condi-
tions as may be necessary to meet the applicable provisions of Section 422 of
the Code.
13.2. Contract Rights; Amendment. Any obligation of AEP to any Participant
with respect to an Award shall be based solely upon contractual obligations
created by an Award Agreement. No Award shall be enforceable until the Award
Agreement has been signed on behalf of AEP by its authorized representative
and signed by the Participant and returned to AEP. By executing the Award
Agreement, a Participant shall be deemed to have accepted and consented to the
terms of this Plan and any action taken in good faith under this Plan by and
within the discretion of the Committee, the Board or their delegates. Award
Agreements covering outstanding Awards may be amended or modified by the Com-
mittee in any manner that may be permitted for the grant of Awards under the
Plan, subject to the consent of the Participant to the extent provided in the
Award Agreement.
14. General Provisions
14.1. Limits on Transfer of Awards; Beneficiaries. Solely to the extent
permitted by the Committee in an Award Agreement and subject to such terms and
conditions as the Committee shall specify, Awards shall be nontransferable
otherwise than as designated by the Participant by will or by the laws of de-
scent and distribution and, during the lifetime of a Participant, Awards shall
be exercised only by such Participant or by his guardian or legal representa-
tive. Notwithstanding the foregoing, the Committee may provide in the terms of
an Award Agreement that the Participant shall have the right to designate a
beneficiary or beneficiaries who shall be entitled to any rights, payments or
other benefits specified under an Award Agreement following the Participant's
death.
14.2. Deferrals of Payment. The Committee may permit a Participant to defer
the receipt of payment of cash or delivery of shares of Common Stock that
would otherwise be due to the Participant by virtue of the exercise of a right
or the satisfaction of vesting or other conditions with respect to an Award.
If any such deferral is to be permitted by the Committee, the Committee shall
establish the rules and procedures relating to such deferral, including, with-
out limitation, the period of time in advance of payment when an election to
defer may be made, the time period of the deferral and the events that would
result in payment of the deferred amount, the interest or other earnings at-
tributable to the deferral and the method of funding, if any, attributable to
the deferred amount.
14.3. Rights as Shareholder. A Participant shall have no rights as a holder
of Common Stock with respect to any unissued securities covered by an Award
until the date the Participant becomes the holder of record of these securi-
ties. Except as provided in Section 3.4 hereof, no adjustment or other provi-
sion shall be made for dividends or other shareholder rights, except to the
extent that the Award Agreement provides for Dividend Equivalents, dividend
payments or similar economic benefits.
A-9
<PAGE>
14.4. Employment or Service. Nothing in the Plan, in the grant of any Award
or in any Award Agreement shall confer upon any Eligible Person the right to
continue in the capacity in which he is employed by or otherwise serves AEP or
any Subsidiary.
14.5. Securities Laws. No shares of Common Stock will be issued or trans-
ferred pursuant to an Award unless and until all then applicable requirements
imposed by federal and state securities and other laws, rules and regulations
and by any regulatory agencies having jurisdiction, and by any stock exchanges
upon which the Common Stock may be listed, have been fully met. As a condition
precedent to the issuance of shares pursuant to the grant or exercise of an
Award, AEP may require the Participant to take any reasonable action to meet
such requirements. The Committee may impose such conditions on any shares of
Common Stock issuable under the Plan as it may deem advisable, including,
without limitation, restrictions under the Securities Act of 1933, as amended,
under the requirements of any stock exchange upon which such shares of the
same class are then listed, and under any blue sky or other securities laws
applicable to such shares.
14.6. Tax Withholding. The Participant shall be responsible for payment of
any taxes or similar charges required by law to be withheld from an Award or
an amount paid in satisfaction of an Award, which shall be paid by the Partic-
ipant on or prior to the payment or other event that results in taxable income
in respect of an Award. The Award Agreement shall specify the manner in which
the withholding obligation shall be satisfied with respect to the particular
type of Award.
14.7. Unfunded Plan. The adoption of this Plan and any setting aside of
cash amounts or shares of Common Stock by AEP with which to discharge its ob-
ligations hereunder shall not be deemed to create a trust or other funded ar-
rangement. The benefits provided under this Plan shall be a general, unsecured
obligation of AEP payable solely from the general assets of AEP, and neither a
Participant nor the Participant's permitted transferees or estate shall have
any interest in any assets of AEP by virtue of this Plan, except as a general
unsecured creditor of AEP. Notwithstanding the foregoing, AEP shall have the
right to implement or set aside funds in a grantor trust subject to the claims
of AEP's creditors to discharge its obligations under the Plan.
14.8. Other Compensation and Benefit Plans. The adoption of the Plan shall
not affect any other stock incentive or other compensation plans in effect for
AEP or any Subsidiary, nor shall the Plan preclude AEP from establishing any
other forms of stock incentive or other compensation for employees of AEP or
any Subsidiary. The amount of any compensation deemed to be received by the
Participant pursuant to an Award shall not constitute compensation with re-
spect to which any other employee benefits of such Participant are determined,
including, without limitation, benefits under any bonus, pension, profit shar-
ing, life insurance or salary continuation plan, except as otherwise specifi-
cally provided by the terms of such plan.
14.9. Plan Binding on Successors. The Plan shall be binding upon AEP, its
successors and assigns, and the Participant, his executor, administrator and
permitted transferees and beneficiaries.
14.10. Construction and Interpretation. Whenever used herein, nouns in the
singular shall include the plural, and the masculine pronoun shall include the
feminine gender. Headings of Sections hereof are inserted for convenience and
reference and constitute no part of the Plan.
14.11. Severability. If any provision of the Plan or any Award Agreement
shall be determined to be illegal or unenforceable by any court of law in any
jurisdiction, the remaining provisions hereof and thereof shall be severable
and enforceable in accordance with their terms, and all provisions shall re-
main enforceable in any other jurisdiction.
14.12. Governing Law. The laws of the State of Ohio shall govern the valid-
ity and construction of this Plan and of the Award Agreements, without giving
effect to principles relating to conflict of laws, except to the extent that
such laws may be preempted by Federal law.
A-10
<PAGE>
15. Effective Date, Termination and Amendment
15.1. Effective Date; Shareholder Approval. Subject to approval by the Secu-
rities and Exchange Commission, the Effective Date of the Plan shall be the
date following adoption of the Plan by the Board on which the Plan is approved
by the shareholders of AEP. Grants of Awards under the Plan may be made prior
to the Effective Date (but after adoption of the Plan by the Board), subject to
approval of the Plan by the Securities and Exchange Commission and the share-
holders. At the sole discretion of the Board, in order to comply with the re-
quirements of Section 162(m) for certain types of Awards under the Plan, the
performance criteria set forth in Section 9.3 shall be reapproved by the share-
holders no later than the first shareholder meeting that occurs in the fifth
calendar year following the calendar year of the initial shareholder approval
of such performance criteria.
15.2. Termination. The Plan shall remain in effect until terminated by ac-
tion of the Board; provided, however, that no Incentive Stock Option may be
granted hereunder after the tenth anniversary of the date the Plan is adopted
by the Board.
Notwithstanding the foregoing, no termination of the Plan shall in any man-
ner affect any Award theretofore granted without the consent of the Participant
or the permitted transferee of the Award.
15.3. Amendment. The Board may at any time and from time to time and in any
respect, amend or modify the Plan; provided, however, that no amendment or mod-
ification of the Plan shall be effective without the consent of AEP's share-
holders that would (a) increase the number of shares of Common Stock reserved
for issuance or (b) allow the grant of Options at an exercise price below Fair
Market Value (except as otherwise permitted by Section 6.2), or allow the
repricing of Options without AEP shareholder approval. In addition, the Board
may seek the approval of any amendment or modification by AEP's shareholders to
the extent it deems necessary or advisable in its sole discretion for purposes
of compliance with Section 162(m) or Section 422 of the Code, the listing re-
quirements of the New York Stock Exchange or for any other purpose. No amend-
ment or modification of the Plan shall in any manner affect any Award thereto-
fore granted without the consent of the Participant or the permitted transferee
of the Award.
A-11
<PAGE>
[LOGO OF AMERICAN ELECTRIC POWER]
[GRAPHIC] PRINTED WITH SOY INK
[LOGO] RECYCLED PAPER
<PAGE>
PROXY
AMERICAN ELECTRIC POWER COMPANY, INC.
Proxy Solicited on Behalf of the Board of Directors
for the Annual Meeting to be held April 26, 2000
- --------------------------------------------------------------------------------
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, with power of substitution, to
represent the undersigned at the annual meeting of shareholders of American
Electric Power Company, Inc. to be held on April 26, 2000, and at any
adjournments thereof, and to vote all shares of Common Stock of the Company
which the undersigned is entitled to vote on all matters coming before said
meeting.
Trustee's Authorization. The undersigned authorizes Fidelity Management Trust
Company 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.W. Fri, 04. L.A. Hudson, Jr., 05. L.J. Kujawa, 06. D.G. Smith, 07. L.G.
Stuntz, 08. K.D. Sullivan, 09. M. Tanenbaum, Central and South West Corp.
Nominees (Assumes Prior Election to Board), 10. E.R. Brooks, 11. D.M. Carlton,
12. W.R. Howell, 13 J.L. Powell, 14. R.L. Sandor, 15. T.V. Shockley, III.
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 OF AEP]AMERICAN(R) ELECTRIC POWER
Admission Ticket
- --------------------------------------------------------------------------------
Annual Meeting of Shareholders
Wednesday, April 26, 2000 . 9:30 a.m.
Fawcett Center
The Ohio State University
2400 Olentangy River Road
Columbus, Ohio
Agenda
. Introduction and Welcome
. Election of Directors
. Ratification of Auditors
. Approval of AEP 2000 Long-Term Incentive Plan
. Chairman's Report
. Comments and Questions from Shareholders
- --------------------------------------------------------------------------------
Directions to the Fawcett Center
(614)292-1342
State Route 315 to the Lane Avenue exit,
Go East on Lane Avenue.
Take Lane Avenue to Olentangy River Road.
Turn North (a left turn) on Olentangy River Road.
The Fawcett Cetner is the first driveway on the East (right) side of the
Olentangy River Road.
[MAP]
- --------------------------------------------------------------------------------
If you plan to attend the annual meeting, please bring this admission ticket
with you.
<PAGE>
[X] Please mark your votes as in this example. 0116
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 Proposals
2 and 3.
- --------------------------------------------------------------------------------
The Board of Directors recommends a vote FOR all Nominees for election as
directors and FOR Proposals 2 and 3.
- --------------------------------------------------------------------------------
FOR WITHHELD
1. Election of Directors (see Reverse). [_] [_]
For, except vote withheld from the following nominee(s):
- ------------------------------------------------------
FOR AGAINST ABSTAIN
2. Approval of Auditors. [_] [_] [_]
3. Approval of AEP 2000 Long-Term
Incentive Plan. [_] [_] [_]
- --------------------------------------------------------------------------------
SPECIAL ATTENTION
Mark here if you have a 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.
, 2000
- ----------------------------------------------
, 2000
- ----------------------------------------------
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 an 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
[GRAPHIC] PRINTED WITH SOY INK
[LOGO] RECYCLED PAPER
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
<CAPTION>
Year Ended December 31, 1999 1998 1997 1996 1995
<S> <C> <C> <C> <C> <C>
INCOME STATEMENTS DATA (in millions):
Total Revenues $6,916 $6,397 $5,928 $5,861 $5,673
Operating Income 1,305 1,247 1,346 1,369 1,254
Income Before Extraordinary Item 520 536 620 587 530
Extraordinary Loss -
UK Windfall Tax - - 109 - -
Net Income 520 536 511 587 530
December 31, 1999 1998 1997 1996 1995
BALANCE SHEETS DATA (in millions):
Property, Plant and Equipment $22,205 $21,351 $20,005 $19,289 $18,815
Accumulated Depreciation
and Amortization 9,150 8,549 8,087 7,656 7,206
Net Property,
Plant and Equipment $13,055 $12,802 $11,918 $11,633 $11,609
Total Assets $21,488 $19,483 $16,615 $15,883 $15,900
Common Shareholders' Equity 5,006 4,842 4,677 4,545 4,340
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 45 46 47 90 148
Subject to Mandatory Redemption* 119 128 128 510 523
Long-term Debt* 7,447 7,006 5,424 4,884 5,057
Obligations Under Capital Leases* 520 533 538 414 405
*Including portion due within one year
Year Ended December 31, 1999 1998 1997 1996 1995
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $2.69 $ 2.81 $3.28 $3.14 $2.85
Extraordinary Loss - UK Windfall Tax - - (0.58) - -
Net Income $2.69 $ 2.81 $2.70 $3.14 $2.85
Average Number of Shares
Outstanding (in millions) 193 191 189 187 186
Market Price Range: High $48-3/16 $53-5/16 $ 52 $44-3/4 $40-5/8
Low 30-9/16 42-1/16 39-1/8 38-5/8 31-1/4
Year-end Market Price 32-1/8 47-1/16 51-5/8 41-1/8 40-1/2
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 89.1% 85.4% 88.7%(a) 76.5% 84.1%
Book Value per Share $25.79 $25.24 $24.62 $24.15 $23.25
(a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73.1%.
</TABLE>
<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;
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 net
regulatory assets and other stranded costs in connection with 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 efforts to restart its nuclear generating units
which are on an extended safety related shutdown; the outcome of litigation
with the Internal Revenue Service related to certain interest deductions
for a corporate owned life insurance program; the ability of the Company
to successfully challenge new environmental regulations and to successfully
litigate claims that the Company violated the Clean Air Act; inflationary
trends; changes in electricity and gas market prices; interest rates; and
other risks and unforeseen events.
American Electric Power (AEP or the Company), one of the United
States' (U.S.) largest investor-owned electric utilities, is a global
energy company. Its domestic regulated electric utility operations provide
electric power to 3 million retail customers in Indiana, Kentucky,
Michigan, Ohio, Tennessee, Virginia and West Virginia and markets, trades
and transmits electricity in most of the Northern and Eastern U.S. AEP's
worldwide electric and gas operations has holdings in the U.S., the United
Kingdom (U.K.), Australia, China and Mexico. These holdings include
electric distribution systems in the U.K. and Australia; generation assets
in China; a Louisiana gas storage facility, an intrastate gas pipeline
operation and a gas trading business in the U.S.; generation facilities
under construction in Mexico; and an energy trading business in a
developmental stage in Europe. Subsidiaries also provide power engineering
and construction, energy consulting and energy management services
worldwide. The businesses that comprise worldwide operations are not
cost-based rate regulated for accounting purposes, although they are generally
subject to different forms of price regulation. As a result regulatory
assets and liabilities are not recorded for the worldwide operations. In
December 1997 the Company announced plans to merge with CSW, another
investor owned electric utility with regulated operations in Arkansas,
Louisiana, Oklahoma and Texas; global energy investments in the U.K.,
Brazil, Chile and Mexico and ownership interests in non-regulated
generating plants in Florida, Texas and Colorado.
Management faced many challenges in 1999 including:
Managing the Cook Nuclear Plant restart efforts under Nuclear
Regulatory Commission (NRC) supervision and the recovery of the
restart costs in regulated rates,
Working with regulators to secure approval of the AEP-CSW merger,
Managing energy-related investments in the U.K., China and Australia,
Operating the newly acquired Louisiana Intrastate Gas (LIG), a fully
integrated natural gas gathering, processing, storage and
transportation operation in Louisiana,
Growing the electricity and gas trading operations,
Implementing laws, passed in 1999, for electric competition in Ohio
and Virginia,
Working to shape restructuring legislation to make it fair and
advantageous to all interested stakeholders and to recover generation
related stranded costs including regulatory assets,
Dealing with actions and litigation against the Company's coal-fired
generating plants by the U.S. Environmental Protection Agency
(Federal EPA) and certain northeastern states, and
Working to mitigate new U.K. price constraints.
Although earnings will continue to be adversely affected by the
expenditures to restart the Cook nuclear units, we expect positive things
to occur in 2000 including the restart of the Cook Plant units and the
consummation of the merger with CSW. Management expects earnings to
recover in 2001 when both Cook nuclear units are expected to be in service
for the full year. Although AEP's three-year total shareholder return was
in the top quartile of the S&P Electric Utility Index for 1997, AEP's
three-year total shareholder return ranked 25th among the companies in the
S&P Electric Utility Index for 1999, reflecting the decline in AEP's common
stock price. The decline in AEP's stock price in 1999, in management's
opinion, reflects the uncertainties associated with the Cook Plant restart
and the consummation of the merger with CSW as well as a general decline
in the utility sector.
<PAGE>
Results of Operations
Net Income
Net income for 1999 declined 3% to $520 million or $2.69 per share
from $536 million or $2.81 per share in 1998 primarily due to increased
costs of the Cook Plant restart efforts and moderation of extreme weather
experienced in the summer of 1998. In 1998 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 U.K.'s
one-time windfall tax which was based on a revision or recomputation of the
original privatization value of certain privatized utilities, including
Yorkshire Electricity Group plc (Yorkshire).
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 at the Cook Plant, a write-down of Yorkshire's
investment in Ionica, a U.K. telecommunications company, severance accruals
for reductions in power generation and energy delivery staff and mild
winter and fall weather.
Revenues Increase
Total revenues increased 8% in 1999 and 1998. Revenues increased in
1999 primarily due to the worldwide electric and gas operations' sale of
electricity in Australia and China and gas in the U.S. These transactions
are primarily from the activities of businesses acquired in December 1998,
CitiPower in Australia and LIG, and the commencement of commercial
operation of a two-unit 250 megawatt (MW) coal-fired generating plant in
China. The 1998 increase was primarily due to increased revenues from
retail, wholesale and transmission service customers in the Company's
domestic regulated electric utility operations.
The table below shows the changes in the components of revenues from
domestic regulated electric utility operations and the increase in
worldwide electric and gas operations. Revenues from the domestic
regulated electric utility operations decreased slightly in 1999 and
increased 8% in 1998. The worldwide electric and gas operations revenues
increased significantly in 1999 following a 6% increase in 1998.
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1999 1998
Amount % Amount %
Domestic Regulated
Electric Utility
Operations:
Retail:
Residential $ 66 $ 37
Commercial 47 57
Industrial (11) 90
Other 1 4
103 2.0 188 3.8
Wholesale (191)(19.0) 207 25.9
Transmission (6) (3.3) 68 61.7
Other 63 106.1 3 4.8
Total Domestic
Regulated
Electric Utility
Operations (31) (0.5) 466 7.9
Worldwide Electric
and Gas Operations 550 N.M. 3 6.3
Total $ 519 8.1 $469 7.9
N.M. = Not Meaningful.
In 1999 retail revenues increased 2% reflecting a 2% increase in
retail sales. Sales to residential and commercial customers increased 4%
reflecting colder winter weather and customer growth.
Retail revenues increased 4% in 1998 reflecting a 2% rise in sales and
increased retail fuel cost recoveries. The increase in retail fuel
recoveries reflects the greater use of internal higher cost coal fired
generation and purchased power partially resulting from the need to replace
nuclear power usually generated at the Cook Plant. Although residential
sales were flat reflecting mild winter and fall weather in 1998, revenues
from residential customers increased 2%. The accrual of fuel-related
revenues for the recovery of the higher cost Cook Plant replacement energy
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 commercial 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.
Wholesale revenues declined 19% in 1999 predominantly due to a
decrease in wholesale energy sales and a reduction in net revenues from
power trading due to a decline in margins. The decrease in wholesale sales
reflects the expiration in July 1998 of a power contract which supplied
power to several municipal customers and the decision by another wholesale
customer who buys energy under a unit power agreement not to take energy
from AEP during an outage of that unit. The decline in margins reflects
the moderation of extreme weather and capacity shortages experienced in the
summer of 1998. The Company engages in the trading of electricity with
other utilities and power marketers in the Company's traditional marketing
area. 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.
The 26% increase in wholesale revenues in 1998 is attributable to net
revenues from trading of electricity and increased power marketing sales.
Although 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.
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. Open transmission access
rules issued in 1996 by the FERC and the expansion of wholesale power
marketing has contributed to growth in the use of AEP's transmission
services.
In 1999 other revenues increased substantially due to a favorable
adjustment to a provision for revenue refund in the Company's Virginia
jurisdiction in connection with the commission's final order and increased
rental income. The increase in rental income reflects agreed to revisions
in the billings for pole attachments with telecommunications companies.
The level of wholesale transactions, including transmission services,
tends to fluctuate due to the highly competitive nature of the short-term
(spot) 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 transmission service
revenues as more electricity is traded in the short-term market.
Operating Expenses Increase
Operating expenses increased 9% in 1999 and 12% in 1998. The
increases were attributable to acquisitions in late 1998 of new worldwide
electricity and gas operations and the costs to restart the shutdown Cook
Plant nuclear generating units. Exclusive of these factors operating
expenses actually declined in 1999. Changes in the components of operating
expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1999 1998
Amount % Amount %
Fuel and
Purchased Power $(38) (1.8) $392 22.2
Maintenance and
Other Operation 22 1.2 135 7.9
Depreciation and
Amortization 20 3.4 (11) (1.9)
Taxes Other Than
Income Taxes 1 0.2 6 1.3
Worldwide Electric
and Gas
Operations 456 480.0 46 93.9
Total $461 9.0 $568 12.4
The decline in fuel and purchased power expense in 1999 is primarily
due to a decrease in fuel expense as generation declined 2% reflecting
lower demand for electricity by the Company's firm wholesale customers.
Firm wholesale customers include municipal distribution systems that
purchase electricity at wholesale to supply the needs of their retail
customers and unaffiliated electric utilities that buy power under long-term
contracts. The expiration in July 1998 of a contract to supply
several municipal customers and the outage of an AEP generating unit with
a long-term unit power agreement accounted for the reduced demand.
Fuel and purchased power expense increased significantly in 1998
primarily due to additional purchases of electricity for resale to other
utilities and power marketers and for replacement of energy usually
generated by the Cook Plant. Both of Cook's nuclear generating units were
unavailable due to the unplanned safety related shutdown which began in
September 1997 and continued throughout 1999. Also contributing to the
increase in fuel and purchased power expense was an increase in the average
cost of fuel consumed reflecting the reduced availability of lower cost
nuclear generation.
<PAGE>
The increase in maintenance and other operation expense in 1999 is
primarily due to the cost of restart efforts at the Cook Plant. The
increased Cook Plant restart expenditures were partially offset by cost
containment efforts in power generation, transmission and distribution and
lower costs to restore service after severe weather damage to the Company's
transmission and distribution system in 1998. The increase in maintenance
and other operation expenses in 1998 is primarily due to the extended Cook
Plant outage, power marketing and trading costs associated with the efforts
of AEP to build a major power trading business, severance accruals for
reductions in power generation and energy delivery staff and costs to
restore service interrupted by two severe snowstorms in the winter of 1998.
Expenses of the Company's worldwide electric and gas operations
increased significantly in 1999 and 1998 due to the addition of expenses
of the businesses acquired in December 1998 and the commercial operation
of the generating units constructed in China. LIG was acquired on December
1, 1998 resulting in one month of operating costs being included in AEP's
1998 operating costs and CitiPower, an Australian electric distribution
business, was acquired on December 31, 1998. Both acquisitions were
accounted for using the purchase method which recognizes revenues and costs
from the purchase date.
Interest and Preferred Dividends
The significant increase in interest and preferred dividends in 1999
reflects increased borrowings to support the expansion of AEP's worldwide
electric and gas operations and related acquisitions including CitiPower
and LIG in December 1998.
<PAGE>
Income Taxes
Income taxes declined in 1999 primarily due to an increase in foreign
tax credits and a decrease in state income taxes.
The decrease in income tax expense in 1998 was primarily due to a
decrease in pre-tax income excluding the extraordinary loss for the U.K.
windfall tax.
Business Outlook - Domestic Regulated Electric Utility Operations
The most significant factors affecting the Company's future earnings
from its domestic regulated electric utility operations are the restart of
the Cook Plant; weather in the Company's service territory; the ability to
recover costs including a fair return on equity in the Company's regulated
electric distribution business and its generation business which is being
restructured in certain regulatory jurisdictions to a competitive market;
the ability to manage costs and risks in the Company's domestic regulated
electric utility operations; the consummation of the CSW merger and the
realization of related net cost savings and the outcome of ongoing
environmental litigation and proposed air quality standards. In 1999
significant progress was made related to many of these major challenges.
Nuclear Plant Restart Effort
Management shut down both units of the Cook Plant in September 1997
due to questions regarding the operability of certain safety systems that
arose during a NRC architect engineer design inspection. The NRC issued
a Confirmatory Action Letter in September 1997 requiring the Company to
address certain issues identified in the letter. In 1998 the NRC notified
the Company that it had convened a Restart Panel for Cook Plant and
provided a list of required restart activities. In order to identify and
resolve all issues necessary to restart the Cook units, the Company is
working with the NRC and will be meeting with the Panel on a regular basis
until the units are returned to service. In a February 2, 2000 letter from
the NRC, the Company was notified that the Confirmatory Action Letter had
been closed. Closing of the Confirmatory Action Letter is one of the key
approvals needed to restart the nuclear units.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to restart in April 2000 and Unit 1 scheduled to restart in
September 2000. The restart plan was developed based upon a comprehensive
systems readiness review of all operating systems at the Cook Plant. When
maintenance and other work including testing required for restart are
complete, the Company will seek concurrence from the NRC to restart the
Cook Plant units. Any issues or difficulties encountered in testing of
equipment as part of the restart process could delay the scheduled restart
dates. Earnings for 2000 will be adversely affected by restart expenses
expected to be incurred in 2000, which are estimated to be $200 million,
and amortization of previously deferred non-fuel restart costs and
fuel-related revenues of $78 million.
Replacement of the steam generator for Unit 1 will be completed before
it is returned to service. Costs associated with the steam generator
replacement are estimated to be approximately $165 million, which will be
accounted for as a capital investment unrelated to the restart. At
December 31, 1999, $119 million has been spent on the steam generator
replacement.
The cost of electricity supplied to retail customers increased due to
the outage of the two Cook Plant nuclear units since higher cost coal-fired
generation and coal-based purchased power is being substituted for the
unavailable low cost nuclear generation. With regulator approvals, actual
replacement energy fuel costs that exceeded the costs reflected in billings
were recorded as a regulatory asset under the Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms.
On March 30, 1999, the Indiana Utility Regulatory Commission (IURC)
approved a settlement agreement that resolved all matters related to the
recovery of replacement energy fuel costs and all outage/restart costs and
related issues during the extended outage of the Cook Plant. The
settlement agreement provided for, among other things, a replacement fuel
billing credit of $55 million, including interest, to Indiana retail
customers' bills; the deferral of unrecovered fuel revenues accrued between
September 9, 1997 and December 31, 1999, including the billing credit; the
deferral of up to $150 million of restart related nuclear operation and
maintenance costs in 1999 above the amount included in base rates; the
amortization of the deferred fuel and non-fuel operation and maintenance
cost deferrals over a five-year period ending December 31, 2003; a freeze
in base rates through December 31, 2003; and a fixed fuel recovery charge
until March 1, 2004. The $55 million credit was applied to retail
customers' bills during the months of July, August and September 1999.
On December 16, 1999, the Michigan Public Service Commission (MPSC)
approved a settlement agreement for two open Michigan power supply cost
recovery reconciliation cases which resolves all issues related to the Cook
Plant extended outage. The settlement agreement limits the Company's
ability to increase base rates and freezes the power supply cost recovery
factor for five years; permits the deferral of up to $50 million in 1999
of jurisdictional non-fuel restart nuclear operation and maintenance
expenses and authorizes the amortization of power supply cost recovery
revenues accrued from September 9, 1997 to December 31, 1999 and non-fuel
nuclear operation and maintenance costs deferrals over a five-year period
ending December 31, 2003.
Expenditures to restart the Cook units are estimated to total
approximately $574 million. Through December 31, 1999, $373 million has
been spent. These expenditures are not capital in nature and as such have
negatively affected current earnings and will negatively affect earnings
in 2000, and through amortization of the above described deferrals through
December 31, 2003. In 1999 the restart costs incurred were $289 million
of which $200 million were deferred for amortization over a five-year
period beginning January 1, 1999 in accordance with the settlement
agreements. Consequently, $129 million of restart costs negatively
affected 1999 earnings inclusive of $40 million of amortization of deferred
restart costs. At December 31, 1999, regulatory assets included $160
million of deferred restart related operation and maintenance costs. Also
deferred as a regulatory asset at December 31, 1999 was $150 million of
Cook fuel-related revenues .
The costs of the extended outage and restart efforts will have a
material adverse effect on future results of operations and possibly
financial condition through 2003 and on cash flows through 2000.
Management believes that the Cook units will be successfully restarted in
April and September 2000, however, if for some unknown reason the units are
not returned to service or their restart is delayed significantly it would
have an even greater adverse effect on future results of operations, cash
flows and financial condition.
Ohio Restructuring and The Transition To Market Pricing For Generation
The Ohio Electric Restructuring Act of 1999 (the Act) became law in
October 1999. The Act provides for customer choice of electricity
supplier, a residential rate reduction of 5% for the generation portion of
rates and a freezing of the unbundled generation rates including fuel rates
beginning on January 1, 2001. The Act also provides for a five-year
transition period to move from cost based rates to market pricing for
generation services. It authorizes the Public Utilities Commission of Ohio
(PUCO) to address certain major transition issues including unbundling of
rates and the recovery of transition costs including stranded costs.
Transition costs include generation-related regulatory assets, (which
include, among other expense deferrals, unrecovered deferred fuel costs,
deferred tax benefits that were flowed through to reduce past rates and
deferred affiliated mine shutdown costs), impaired tangible generating
asset values, and future contract costs. Stranded costs are those costs
of generation above market that would not be recoverable in a competitive
market. Transition costs also include customer choice education costs,
development costs of new billing and metering systems, costs of filing a
transition plan, employee severance and retraining costs and other costs.
Retail electric services that will be competitive are defined in the
Act as electric generation service, aggregation service, and power
marketing and brokering. Under the Act the PUCO is granted broad oversight
responsibility and is required to approve by October 31, 2000 a transition
plan for each electric utility company. Ohio electric utilities were
required to file their transition plans by January 3, 2000. The Company
filed its plan in December 1999.
The Act provides Ohio electric utilities with an opportunity to
recover PUCO approved allowable transition costs through the generation
portion of transition rates paid through December 31, 2005 by customers who
do not switch generation suppliers and through a transition charge for
customers who switch generation suppliers. Under the Act recovery of the
regulatory asset portion of transition costs can, under certain
circumstances, extend beyond the five-year transition period but cannot
continue beyond December 31, 2010.
The Act also provides for a reduction in property tax assessments;
exemption of electric utilities from the gross receipts tax; and the
imposition of a franchise tax, income taxes, and a new kilowatthour (kwh)
excise tax. The property tax assessment percentage on electric generation
property will be lowered from 100% to 25% of value effective January 1,
2001 and electric utilities will become subject to the Ohio Corporate
Franchise Tax and municipal income taxes on January 1, 2002. The last year
for which electric utilities will pay a tax based on gross receipts is the
tax year ending April 30, 2002. As of May 1, 2001 electric distribution
companies will be subject to an excise tax based on kwh sold to Ohio
customers. The gross receipts tax, which will terminate for electric
utilities, is paid by the Company at the beginning of the tax year,
deferred as a prepaid expense and amortized to expense during the tax year
pursuant to the tax law whereby the payment of the tax results in the
privilege to conduct business in the year following the payment of the tax.
The change in the tax law to impose an excise tax based on kwh sold to Ohio
customers commencing before the expiration of the gross receipts tax
privilege period will result in a 12 month period (May 1, 2001 to April 30,
2002) when our Ohio electric utilities are recording as an expense both the
gross receipts tax and the kwh excise tax. In the Company's Ohio
transition plan filing, recovery of $90 million was sought for this overlap
of the gross receipts and excise taxes.
The PUCO is required to issue a transition order no later than October
31, 2000 regarding the Company's transition filings which included the
following elements:
a rate unbundling plan including tariff terms and conditions
necessary for restructuring,
a corporate separation plan,
an application for transition revenues,
a plan for independent operation of transmission facilities and
other components for the implementation of restructuring.
The rate unbundling portion of the Company's transition plan filing
provides for the Company's Ohio retail jurisdictional companies to offer
two transition period tariffs beginning January 1, 2001, the standard
tariff and the open access distribution tariff. The Company's proposed
standard tariff applies to customers who do not choose an alternative
energy supplier. This tariff schedule includes detailed charges for
generation, transmission and distribution and riders to fund universal
service, to promote energy efficiency and to recover regulatory assets and
taxes. Taxes include charges for municipal income, excise and franchise
taxes and tax credits for gross receipts and property taxes. For customers
who choose an alternative electric supplier, the proposed open access
distribution tariff will apply. This tariff includes charges for
distribution and riders to fund universal service, to promote energy
efficiency and to recover regulatory assets and taxes. These riders are
the same as those in the standard tariff except there is no property tax
credit.
The Company's corporate separation plan proposal requires that each
of the Company's Ohio jurisdictional companies establish separate
subsidiaries to own and operate their transmission and distribution assets.
The separation plan will be implemented in a manner that recognizes the
current overlap of financing arrangements. This would permit an orderly
and economically efficient separation of each operating company so that
additional transition costs from prematurely retiring of financial
instruments can be avoided. Prior to the actual legal separation, the Ohio
jurisdictional companies will functionally separate generation from
transmission and distribution.
The transition plan filing requests recovery of stranded generation
costs over a five year period and recovery of generation-related regulatory
assets and other transition costs of $974 million over a 10-year period
through transition revenues. The amount requested for recovery of
regulatory assets includes current and new regulatory assets including
those arising from compliance with the electric restructuring law. Also
included in the requested recovery amount were deferred fuel and affiliated
mine closure costs.
In the Ohio jurisdiction the Company is subject to certain limitations
on the current recovery of affiliated coal costs under PUCO approved
agreements, which are discussed in Note 3 of the Notes to Consolidated
Financial Statements. Under the terms of the agreements full recovery of
the Ohio jurisdictional portion of deferred unrecovered costs of affiliated
mining operations including future mine closure costs was expected to occur
before the expiration of the PUCO approved agreements in 2009. Management
closed the Muskingum mine in 1999 and plans to close the Windsor mine in
2000 and the Meigs mine in 2001. Provisions for Muskingum and Windsor mine
shutdown costs totaling $45 million and $48 million were recorded in 1998
for Muskingum mine and 1999 for the Windsor mine, respectively. Management
deferred these provisions in the Ohio jurisdiction under the PUCO approved
agreements because it believed that these deferrals for the cost of the
mine shutdowns are probable of future recovery through the agreements.
However, since the Act will supersede the agreements effective January 1,
2001, the Company has filed under the provisions of the Act for recovery
of all of its stranded regulatory assets including the affiliated coal
costs deferred under the agreements of $196 million at December 31, 1999
plus the projected amount that will be deferred by the beginning of the
transition period, January 1, 2001, which includes the accrual for the
closure costs of the Meigs mine.
Included in the transition plan is a proposal to implement independent
operation of the transmission system. The Company proposes to join a
regional transmission organization (RTO) whose approval is currently
pending before the Federal Energy Regulatory Commission (FERC).
See Note 5 of the Notes to Consolidated Financial Statements for
further discussion.
Virginia Restructuring
In March 1999 a law was enacted in Virginia to restructure the
electric utility industry. Under the restructuring law, a transition to
choice of electricity supplier for retail customers will commence on
January 1, 2002 and be completed, subject to a finding by the Virginia
State Corporation Commission (Virginia SCC) that an effective competitive
market exists, on or before January 1, 2004.
The law also provides an opportunity to recover just and reasonable
net stranded generation costs. The mechanisms in the Virginia law for net
stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the
termination of the rate cap. The law provides for the establishment of
capped rates prior to January 1, 2001 and the establishment of a wires
charge by the fourth quarter of 2001.
West Virginia Restructuring
On January 28, 2000, after over three years of workshops, hearings and
negotiations, the Public Service Commission of West Virginia (WVPSC) issued
an order approving an electricity restructuring plan for West Virginia.
The restructuring plan has been submitted to the West Virginia Legislature
for approval or rejection which is expected to occur during the current
legislative session that ends in March 2000. Until approved by the West
Virginia Legislature, the restructuring plan cannot take effect. The
Company's subsidiaries, Appalachian Power Company (APCo) and Wheeling Power
Company, which do business in West Virginia, will be affected by the
proposed restructuring.
The provisions of the proposed restructuring plan provide for customer
choice to begin on January 1, 2001, or at a later date set by the WVPSC
after all necessary rules are in place (the "starting date"); deregulation
of generation assets occurring on the starting date; functional separation
of the generation, transmission and distribution businesses on the start
date and their legal corporate separation no later than January 1, 2005;
a transition period of up to 13 years, during which the incumbent utility
must provide default service for customers who do not change suppliers
unless an alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13 year
transition period as discussed below; deregulation of metering and billing;
a 0.5 mills per kwh wires charge applicable to all retail customers for the
period January 1, 2001 through December 31, 2010 intended to provide for
recovery of any stranded cost including net regulatory assets;
establishment of a rate stabilization deferred balance by AEP of $81
million by the end of year ten of the transition period to be used as
determined by the WVPSC to offset prices paid in the eleventh, twelfth, and
thirteenth year of the transition period by residential and small
commercial customers that do not choose a supplier.
Default rates for residential and small commercial customers are
capped for four years after the starting date and then increased as
specified in the plan for the next six years. In years eleven, twelve and
thirteen of the transition period, the power supply rate shall equal the
market price of comparable power. Default rates for industrial and large
commercial customers are discounted by 1% for four and a half years,
beginning July 1, 2000, and then increased at pre-defined levels for the
next three years. After seven years the power supply rate for industrial
and large commercial customers will be market based.
Restructuring In Other Jurisdictions
All of the other states within our service territory have initiatives
to implement or review customer choice, although the timing of any
implementation is uncertain. The Company supports customer choice and
deregulation of generation and is proactively involved in discussions
regarding the best competitive market structure and transition method to
arrive at a fair, competitive marketplace. As the pricing of generation
in these markets evolves from regulated cost-of-service rates to
market-based pricing, the recovery of stranded costs including net regulatory
assets and other transition costs must be addressed. The amount of
stranded costs the Company could experience when restructuring occurs in
these jurisdictions depends on the timing and extent to which competition
is introduced to its business and the future market prices of electricity.
The recovery of stranded cost is dependent on the terms of future
legislation and, if required, related regulatory proceedings.
Regulatory/Restructuring Accounting
Under the provisions of Statement of Financial Accounting Standards
(SFAS) 71. "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities (deferred
revenues) are included in the consolidated balance sheets of cost-based
regulated utilities in accordance with regulatory actions in order to match
expenses and revenues. 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 probable recovery of regulatory assets over
future accounting periods. Management has concluded that as of December
31, 1999 the requirements to apply SFAS 71 continue to be met for AEP's
jurisdictions. However, the recent legislation in Ohio and Virginia will
result in the discontinuance of SFAS 71 regulatory accounting for the
generation portion of the Ohio and Virginia jurisdictions. If the West
Virginia Legislature approves the restructuring plan as submitted by the
WVPSC it will result in the discontinuance of SFAS 71 regulatory accounting
for the generation portion of the West Virginia jurisdiction.
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 did not anticipate or provide accounting guidance for an extended
transition period and for recovery of stranded costs during and after a
transition period through a wires charge or regulated distribution rates.
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 that 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 transition to competitive market pricing
from cost-based regulated rates and/or a rate order is issued containing
sufficient detail for the utility to reasonably determine what the
restructuring plan would entail and how it will affect the utility's
financial statements. The EITF indicated that the cessation of application
of SFAS 71 regulatory accounting would require that regulatory assets and
impaired stranded plant cost applicable to the portion of the business that
was no longer cost-based regulated, be written off unless they are
recoverable in the future through transition rates and/or post-transition
cost based regulated rates.
Potential For Write Offs In Ohio, Virginia And West Virginia Jurisdictions
The Company's accounting for generation will continue to be in
accordance with SFAS 71 in the Ohio and Virginia jurisdictions and will
continue to be considered to be cost-based regulated for accounting
purposes until the amount of transition rates and stranded cost wires
charges are determined and known. The establishment of transition rates
and wire charges should enable management to determine the Company's
ability to recover stranded costs including regulatory assets and
transition costs, a requirement under EITF 97-4 to discontinue application
of SFAS 71. When the amount of unbundled frozen generation transition
rates and distribution stranded cost wires charges are known for the Ohio
jurisdiction, the application of SFAS 71 will be discontinued for the Ohio
retail jurisdictional portion of the Company's generation business.
Management expects this to occur when the PUCO issues its order to approve
a transition plan for the Company's Ohio jurisdictional electric operating
subsidiaries. The Act requires that the PUCO issue its order no later than
October 31, 2000. The application of SFAS 71 will be discontinued for the
Virginia retail jurisdictional portion of the Company's generation business
when the capped rates and the wires charge are known in Virginia which is
expected to occur by the fourth quarter of 2000. In the West Virginia
jurisdiction accounting for generation will continue to be in accordance
with SFAS 71 and the generation business will continue to be considered to
be cost-based regulated for accounting purposes until the proposed
restructuring plan is enacted into law. The application of SFAS 71 for the
generation portion of the West Virginia jurisdiction will be discontinued
when the West Virginia Legislature approves the restructuring plan and when
the WVPSC approves the rate stipulation filed with the Commission, which
are both expected to occur in March 2000. Together these two documents
provides sufficient information for management to determine the impact of
restructuring on the Company's financial statements.
Upon the discontinuance of SFAS 71 the Company will have to write off
its Ohio, Virginia and West Virginia jurisdictional generation-related
regulatory assets to the extent that they cannot be recovered under the
frozen transition rates and stranded costs distribution wires charges and
record any asset accounting impairments. An impairment loss would be
recorded to the extent that the cost of generation assets cannot be
recovered through non-discounted generation-related revenues during the
transition period and future market prices. Absent the determination in
the legislative or regulatory process of transition rates, any wires charge
and other pertinent information, it is not possible at this time for
management to determine if any of the Company's generating assets are
impaired for accounting purposes on an undiscounted cash flow basis.
The amount of regulatory assets recorded on the books at December 31,
1999 applicable to the Ohio, Virginia and West Virginia retail
jurisdictional generation business before related tax effects is estimated
to be $666 million, $64 million and $131 million, respectively. Due to the
planned closing of the Company's affiliated mines, including the Meigs
mine, projected generation-related regulatory assets as of December 31,
2000 (the date that recoverable generation related regulatory assets are
measured under the Ohio law) allocable to the Ohio retail jurisdiction are
estimated to exceed $800 million, before income tax effects. Recovery of
these Ohio generation related regulatory assets was sought as a part of the
Company's Ohio transition plan filing. Based on current projections of
future market prices, the Company does not anticipate that it will
experience material tangible asset accounting impairment write-offs.
Whether the Company will experience material regulatory asset write-offs
will depend on whether the PUCO approves the Company's request for their
recovery and whether the capped transition rates and allowed wires charges
in Virginia and West Virginia will permit their recovery.
An estimated determination of whether the Company will experience any
asset impairment loss regarding its Ohio, Virginia and West Virginia
retail jurisdictional generating assets and any loss from the possible
inability to recover Ohio, Virginia and West Virginia generation related
regulatory assets and other transition costs cannot be made until such time
as the transition rates and the wires charges are determined through the
regulatory or legislative process. Should the PUCO or the Virginia SCC
fail to approve transition rates and wires charges that are sufficient to
provide for recovery or the West Virginia Legislature approves a
restructuring plan that does not provide for recovery of the Company's
generation-related regulatory assets, any other stranded costs and
transition costs, it could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
AEP supports the orderly transition to market pricing for electricity
because we believe our low cost generating units provide us with a
competitive advantage provided the legislators and/or regulators provide
a level playing field for all competitors. AEP is working to develop and
acquire the necessary skills and competencies to succeed in a competitive
electricity commodity market. AEP has developed an extensive wholesale
electricity trading business. However, many factors, some of which AEP
does not control, could negatively impact AEP's future success in a market
priced, competitive environment.
Customer choice and competition in AEP's other domestic jurisdictions
could also ultimately result in adverse impacts on results of operations
and cash flows depending on the future market prices of electricity and the
ability of the Company to recover its stranded costs including net
regulatory assets during a transition or subsequent period through a wires
charge or other recovery mechanism. We believe that enabling state
legislation and the regulatory process should provide for the full recovery
of generation related net regulatory assets and other reasonable stranded
costs. However, if in the future any portion of AEP's generation business
in other jurisdictions 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.
Completion of the Merger
In 1999 the Company and CSW made significant progress towards
receiving all the approvals necessary to complete their merger which was
announced in December 1997. FERC and the Securities and Exchange
Commission (SEC) approvals are needed to consummate the merger.
In 1998 the appropriate shareholder approvals were acquired and the
NRC and the Arkansas Public Service Commission approved the merger. In
1998 the FERC issued an order which confirmed that a 250 MW firm contract
path with the Ameren System was available to meet the Public Utility
Holding Company Act of 1935 (1935 Act) requirement that the two electric
transmission systems operate on an integrated and coordinated basis.
During 1999 the regulatory commissions of Louisiana, Texas and Oklahoma
approved the merger and related settlement agreements, and settlements were
reached with the FERC staff and certain other parties who had intervened
in the FERC proceeding or who had asserted a right to review the merger.
The Company reached agreements in 1999 with its state regulatory
commissions in Indiana, Michigan and Kentucky and in 2000 the Department
of Justice closed its investigation.
In granting approval of the merger, the CSW state regulatory
commissions, Arkansas, Louisiana, Oklahoma and Texas, required the Company
to take several steps to protect the interest of their constituents. Among
those requirements are sharing of net merger savings at a rate of
approximately 55% to customers and 45% to the Company's shareholders; a
freezing or capping of base rates for defined periods of three to five
years; joining an RTO; implementing standards to insure quality of service;
divesting 1,604 MW of generation in Texas; agreeing to comply with code of
conduct standards for affiliated transactions, shared cost allocations and
prevention of cross subsidization of non-regulated operations by regulated
operations and other provisions facilitating competition. See Note 7 of
the Notes to Consolidated Financial Statement for additional detail.
Merger settlement agreements were approved in 1999 by the IURC, MPSC
and the Kentucky Public Service Commission (KPSC). The terms of the
settlement agreements provide for, among other things, a 55%/45% sharing
of net merger savings with Indiana, Michigan and Kentucky customers; a
one-year extension through January 1, 2005 of a freeze in base rates in Indiana
and Michigan; additional annual deposits of $6 million to the nuclear
decommissioning trust fund for the Indiana jurisdiction for the years 2001
through 2003; quality-of-service standards for customer service and
reliability; and participation in an RTO; and other steps to protect and
promote fair competition. As part of the settlement agreements, the IURC,
MPSC and the key parties to the Kentucky settlement agreed not to oppose
the merger in the FERC and the SEC proceedings.
AEP and CSW also reached settlements in 1999 with the Missouri Public
Service Commission, the International Brotherhood of Electrical Workers,
representing employees of AEP and CSW, the Utility Worker's Union of
America representing AEP employees, and certain wholesale customers who had
intervened in the FERC proceeding. All have agreed not to oppose the
merger in the FERC and the SEC proceedings. In October 1999 the PUCO
withdrew its opposition to the Company's pending merger with CSW in the
FERC proceeding.
During 1999 FERC reviewed the proposed merger addressing issues of
competition, market power and customer protection. AEP and CSW reached
settlements with the FERC trial staff resolving competition, rate and other
issues relating to the merger. The settlements have been submitted to the
FERC for approval. Under the terms of the settlements, AEP filed an RTO
proposal with the FERC whereby it will transfer the operation and control
of AEP's bulk transmission facilities to an RTO known as the Alliance RTO.
The settlements also cover rates for transmission services and ancillary
service as well as resolving issues related to system integration
agreements and confirm, subject to FERC guidance on certain elements, that
a proposed generation divestiture of up to 550 MW of capacity will satisfy
the FERC staff's market power concerns. Hearings on the merger and related
settlement agreements were held before a FERC administrative law judge
(ALJ) in 1999. In November 1999 the ALJ issued a favorable decision
finding the merger and the proposed settlement agreements to be in the
public interest. The FERC is expected to issue a final order in the first
quarter of 2000. SEC approval of the merger under the 1935 Act is expected
to follow the FERC's issuance of a final order.
The proposed merger of CSW into AEP would result in common ownership
of two U.K. regional electricity companies (RECs), Yorkshire Electricity
Group plc (Yorkshire) and SEEBOARD, plc. AEP has a 50% ownership interest
in Yorkshire and CSW has a 100% interest in SEEBOARD. On January 25, 2000,
the U.K. Department of Trade and Industry approved the common ownership of
two RECs which will result from the consummation of the AEP-CSW merger.
The approval was conditioned on agreement to certain assurances concerning
the U.K. operations of Yorkshire and SEEBOARD including meeting customer
service obligations, maintaining debt ratings of investment grade or above
and separate distribution and supply activities. This approval is the
final clearance for the merger in the U.K.
At December 31, 1999, AEP had deferred $42 million of transaction and
transition costs related to the merger, which will be charged to expense
if AEP and CSW are not successful in completing their proposed merger. If
the merger is consummated, the deferred costs allocable to those regulated
electric operating subsidiaries with merger settlement agreements will be
amortized over a five- to eight-year recovery period depending on the
specific terms of their settlement agreements. The remainder of the
deferred merger costs will be expensed upon consummation of the merger.
Merger transition costs are expected to continue to be incurred and
expensed or deferred for amortization as appropriate for several years
after the merger is consummated.
The merger with CSW is conditioned upon, among other things, the
approval of certain 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 has been extended for six
months until June 30, 2000 by both AEP's and CSW's boards of directors.
Should the merger approval process extend beyond June, either AEP or CSW
could terminate the merger agreement. Although consummation of the merger
is expected to occur in the second quarter of 2000, the Company is unable
to predict the outcome or the timing of the remaining required regulatory
proceedings. If realized merger savings do not match or exceed the
estimated savings included in merger settlement agreements in the
eight-year period following consummation of the merger, future results of
operations, cash flows and possibly financial condition could be adversely
affected.
<PAGE>
Environmental Concerns and Issues
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. AEP has spent
over 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 while providing a vital commodity, electricity, to our
customers at a fair price.
Air Quality
In 1998 Federal EPA issued a final rule which requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern states,
including the states in which the Company's generating plants are located.
A number of utilities, including the Company, filed petitions seeking a
review of the final rule in the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court). On March 3, 2000, the Appeals Court
issued a decision generally upholding Federal EPA's final rule on NOx
emission reductions.
On April 30, 1999, Federal EPA took final action with respect to
petitions filed by eight northeastern states pursuant to the Clean Air Act
(Section 126 Rule). The Rule approved portions of the states' petitions
and imposed NOx reduction requirements on AEP System generating units which
are approximately equivalent to the reductions contemplated by the NOx
emission reduction final rule. The AEP System companies with coal-fired
generating plants, as well as other utility companies, filed a petition in
the Appeals Court seeking review of the Section 126 Rule. In 1999, three
additional northeastern states and the District of Columbia filed petitions
with Federal EPA similar to those originally filed by the eight
northeastern states. Since the petitions relied in part on compliance with
an 8-hour ozone standard remanded by the Appeals Court, Federal EPA
indicated its intent to decouple compliance with the 8-hour standard and
issue a revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126 Rule
requiring 392 industrial plants, including certain generating plants owned
by the Company, to reduce their NOx emissions by May 1, 2003. This rule
approves petitions of four northeastern states which contend that their
failure to meet Federal EPA smog standards is due to coal-fired generating
plants in upwind states, including many of the Company's plants, and not
their automobiles and other local sources.
Preliminary estimates indicate that compliance with the Federal EPA's
final rule on NOx emission reductions that was upheld by the Appeals Court
could result in required capital expenditures of approximately $1.6 billion
for the Company. It should be noted, however, that compliance costs cannot
be estimated with certainty since 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 compliance costs are recovered from customers through regulated
rates and, where generation is being deregulated, unbundled generation
transition rates, wires charges and the future market price of electricity,
such compliance costs will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a plant undergoes a major modification
that results in a significant emissions increase, permitting requirements
might be triggered and the plant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of degraded equipment
or failed components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999, the Department of Justice, at the request of
Federal EPA, filed a complaint in the U.S. District Court for the Southern
District of Ohio that alleges the Company made modifications to certain of
its coal-fired generating plants over the course of the past 25 years that
extend their operating lives or increase their generating capacity in
violation of the Clean Air Act. Federal EPA also issued Notices of
Violation to the Company alleging violations of certain provisions of the
Clean Air Act at certain AEP plants. A number of unaffiliated utilities
also received Notices of Violation, complaints or administrative orders.
The states of New Jersey, New York and Connecticut were subsequently
allowed to join Federal EPA's action against the Company under the Clean
Air Act. On November 18, 1999, a number of environmental groups filed a
lawsuit against power plants owned by the Company alleging similar
violations to those in the Federal EPA complaint and Notices of Violation.
This action has been consolidated with the Federal EPA action. The
complaints and Notices of Violation named 11 of AEP's 17 coal-fired
generating plants. Management believes its maintenance, repair and
replacement activities were in conformity with the Clean Air Act provisions
and intends to vigorously pursue its defense of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500 per day
per violation at each generating unit ($25,000 per day prior to January 30,
1997). Civil penalties, if ultimately imposed by the court, and the cost
of any required new pollution control equipment, if the court accepts all
of Federal EPA's contentions, could be substantial. In the event the
Company does not prevail, any capital and operating costs of additional
pollution control equipment that may be required as well as any penalties
imposed would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered through
regulated rates and, where states are deregulating generation, approved
unbundled transition generation rates, wires charges and future market
prices for electricity.
Business Outlook - Worldwide Electric and Gas Operations
In 1999 no significant new investments were made in the worldwide
electric and gas operations outside the U.S. Management continues to
evaluate its current investments and opportunities for growth with the goal
of maximizing shareholder value. In January 2000 European trading of
electricity and gas began. In 1999 the construction of two generating
units in China was completed on schedule and the Company acquired a 50%
investment interest in a Mexican generation project and commenced energy
trading operations in Canada. This follows acquisitions made in December
1998 to expand AEP's electric and gas operations overseas and in the U.S.
which included the purchase of CitiPower, an Australian electric
distribution utility, and the purchase of LIG's gas operations in Louisiana
and gas trading operation in Houston, Texas.
The most significant factor affecting the Company's future earnings
from its worldwide electric and gas operations is the performance of its
energy investments and business ventures including the ability to control
costs as the U.K. and Australian electricity supply markets are deregulated
and electricity distribution rate regulation becomes more performance
based. The Company continues to evaluate the U.S. and international energy
markets for investment opportunities to create shareholder value. Future
earnings will also be impacted by the performance of any future
acquisitions, mergers and investments.
Pursuant to the 1935 Act, AEP's investment in certain types of
non-regulated energy ventures is limited. SEC authorization under the 1935 Act
limits AEP to issuing and selling securities in an amount up to 100% of its
average quarterly consolidated retained earnings balance (such average
balance was approximately $1.7 billion for the twelve months ended December
31, 1999) for investment in exempt wholesale generators (EWGs) and foreign
utility companies (FUCOs). At December 31, 1999, AEP's investment in EWGs
and FUCOs was $885 million. Management expects to continue to pursue new
and existing energy projects and to provide energy related services
worldwide.
In December 1999 the Company contributed $47 million to acquire a 50%
interest in a Mexican power project. The power project (Bajio) is a 600
MW natural gas-fired, combined cycle plant located approximately 160 miles
from Mexico City. An affiliate of the Company's partner will build the
facility, which is estimated to cost $430 million. The Company is not
expected to contribute any additional capital to the project; the remainder
of the funding will be provided by third party debt some of which will be
supported by letters of credit issued on behalf of the Company. The
facility will be operated and managed by companies jointly owned by the
Company and its partner. Bajio has a 25-year contract to sell 495 MW of
the plant's output to Mexico's federally owned electric system. The
remainder is expected to be sold to industrial customers in the region.
The Bajio power project is expected to be completed in the fall of 2001.
The $1.1 billion acquisition of CitiPower, completed on December 31,
1998, was accounted for using the purchase method of accounting. CitiPower
provides electricity and electric distribution service to approximately
250,000 customers in the city of Melbourne.
In March 1998 the Company acquired a 20% equity interest in Pacific
Hydro. Pacific Hydro operates four hydroelectric power stations in
Australia with an installed capacity of 40 MW and has interests in two
hydroelectric projects under construction in the Philippines.
Two newly constructed 250 MW coal-fired generating units in China,
owned 70% by the Company with the remaining 30% owned by two Chinese
partners, began commercial operation in 1999. Although the units incurred
a loss in 1999, a higher tariff rate approved by the Central Chinese
government in January 2000 should result in the units contributing to the
Company's future earnings.
In addition, the Company has a 50% investment in Yorkshire, a U.K.
supplier of electricity and gas and electric service distribution company.
The investment was made in April 1997 and contributed $45 million and $39
million of equity earnings in 1999 and 1998, respectively, which is
included in worldwide electric and gas operations revenues. Since May 1999
all residential and commercial customers in the U.K. could choose their
electricity supplier. Yorkshire has been successful in maintaining its
customer base since the start of full competition. However, as expected,
margins on retail electric sales have been declining due to competition.
In December 1999 the Office of Gas and Electricity Markets (OFGEM), the
U.K. gas and electric regulatory body, published final proposals for
Yorkshire's new rates in its distribution business and for price caps in
its supply business. The final proposals reduce distribution rates and
electricity supply price caps beginning on April 1, 2000. The rate
reductions and reduced price caps are expected to reduce the Company's
equity earnings from its Yorkshire investment. This reduction may be
significant if it is not offset by increased revenues and/or cost savings.
On December 1, 1998, the Company purchased LIG, a midstream natural
gas operation 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, natural gas processing plants and
natural gas storage facilities. 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.
SEC rules under the 1935 Act permit AEP to invest up to 15% of
consolidated capitalization (such amount was $2 billion at December 31,
1999) in energy-related companies that engage in marketing and/or trading
electricity, gas and other energy commodities. The Company's gas trading
business is reported as an investment under this rule and at December 31,
1999, AEP's investment was $337 million.
Financial Condition
AEP's financial condition continues to be strong. The Cook Plant
extended outage and related restart expenditures negatively affected 1999
earnings and will continue to adversely impact earnings in 2000. The 1999
dividend payout ratio was 89.1% and is expected to increase in 2000 as the
Cook Plant restart is completed. Nonetheless, it has been a management
objective to reduce the payout ratio by increasing earnings.
AEP's ratio of common equity to total capitalization including long-term
debt due within one year was 39.7% on December 31, 1999, compared with
40.3% on December 31, 1998 and 45.5% on December 31, 1997. The decline in
1999 and 1998 primarily reflects borrowing to support the acquisitions and
investments made by the worldwide electric and gas operations. AEP issued
2,287,000 shares of common stock in 1999, 1,826,000 shares in 1998 and
1,755,000 shares in 1997 through a Dividend Reinvestment and Direct Stock
Purchase Plan and the Employee Savings Plan raising $91 million, $86
million and $77 million, respectively. Additional sales of common stock
and/or equity linked securities may be necessary in the future to support
the Company's growth.
Consolidated construction expenditures for all subsidiaries are
expected to be $2.8 billion over the next three years. All expenditures
for domestic regulated electric utility construction, estimated to be $2.5
billion for the next three years, are expected to be financed with
internally generated funds.
Capital Resources - Structure and Liquidity
The Company and its subsidiaries issued $810 million principal amount
of long-term obligations in 1999 at interest rates ranging from 5.15% to
7.45%. The Company also increased its borrowing under two long-term
revolving credit agreement: $60 million under an agreement which expires
in June 2000 and $30 million under an agreement which expires in December
2002. The principal amount of long-term debt retirements, including
maturities, totaled $506 million with interest rates ranging from 6.42% to
9.6%. The ratings of the subsidiaries' first mortgage bonds are listed in
the following table:
Company Moody's S&P Fitch D & P
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
The Company's subsidiaries also issue senior unsecured debt. Their
senior unsecured debt ratings are listed in the following table:
Company Moody's S&P D & P
AEP Resources* Baa2 BBB+ N/A
APCo Baa1 BBB+ A-
CitiPower Baa2 BBB+ N/A
CSPCo Baa1 BBB+ A-
I&M Baa2 BBB BBB
KPCo Baa2 BBB BBB
OPCo Baa1 BBB+ A-
* The rating is for a series of senior notes
issued with a Support Agreement from AEP.
The domestic electric utility 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 sources of funds available to AEP
Co., Inc. are dividends from its subsidiaries, short-term and long-term
borrowings and proceeds from the issuance of common stock.
The subsidiaries formed to pursue worldwide electric and gas
opportunities use short-term debt (through revolving credit facilities) and
capital contributions by the parent company to provide for interim
financing of capital expenditures and acquisitions. Short-term debt is
replaced with long-term debt when financial market conditions are
favorable. Some acquisition transactions of existing business entities
include the assumption of their outstanding debt.
Short-term debt increased $271 million and $62 million in 1999 and
1998, respectively. At December 31, 1999, AEP Co., Inc. (the parent
company) and its subsidiaries had unused short-term lines of credit of
$1,056 million, and another subsidiary had $20 million available under a
$50 million revolving credit agreement that expires in December 2002. An
AEP subsidiary engaged in the acquisitions of worldwide energy investments
and businesses had no funds available under a $600 million revolving credit
agreement that expires in June 2000.
Unless the domestic electric utility subsidiaries meet certain
earnings or coverage tests, they cannot issue additional mortgage bonds.
In order to issue mortgage bonds (without refunding existing debt), each
subsidiary must have pre-tax earnings equal to at least two times the
annual interest charges on mortgage bonds after giving effect to the
issuance of the new debt.
<PAGE>
The following debt coverages of AEP's principal domestic electric
utility subsidiaries remained strong in 1999 and were as follows:
Coverages at
December 31, 1999
Mortgage
APCo 5.29
CSPCo 7.42
I&M 4.81
KPCo 5.57
OPCo 11.78
As the above table indicates, the major domestic electric 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. Policies and
procedures have been established to identify, assess, and manage market
risk exposures including the use of a risk measurement model which
calculates Value at Risk (VaR). The VaR is based on the variance -
covariance method using historical prices to estimate volatilities and
correlations and assuming a 95% confidence level and a three-day holding
period. Throughout 1999 and 1998, the highest, lowest and average VaR in
the wholesale electricity and gas trading portfolio was less than $14
million and $11 million, respectively. Based on this VaR analysis, at
December 31, 1999 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.
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.
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 with terms from one
day to forty years and an average duration of four years at December 31,
1999. The Company measures interest rate market risk exposure utilizing
a VaR model. The interest rate VaR model is based on a Monte Carlo
simulation with a 95% confidence level and a one year holding period. The
volatilities and correlations were based on three years of weekly prices.
The risk of potential loss in fair value attributable to the Company's
exposure to interest rates, primarily related to long-term debt with fixed
interest rates, was $575 million at December 31, 1999 and $589 million at
December 31, 1998. 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 as a hedge 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 80% 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 13
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.
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 in U.S. 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, 1999 would reduce earnings by
approximately $317 million inclusive of interest.
The Company made payments of taxes and interest attributable to COLI
interest deductions for taxable years 1991-98 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 consolidated
balance sheet in other assets pending the resolution of this matter. The
Company is seeking refund through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against the
U.S. in the U.S. District Court for the Southern District of Ohio in March
1998. In 1999 a U.S. Tax Court judge decided in the Winn-Dixie Stores v.
Commissioner case that a corporate taxpayer's COLI deductions should be
disallowed. Notwithstanding the decision in Winn-Dixie management has made
no provision for any possible adverse earnings impact from this matter
because it believes, and has been advised by outside counsel, that it has
a meritorious position and will vigorously pursue its 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 management is 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 or
financial condition.
Other Matters
Superfund
By-products from the generation of electricity include materials such
as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel
(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 Federal EPA to administer the clean-up programs. As
of year-end 1999, we are involved in litigation with respect to two 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 are three
additional sites for which AEP has received information requests which
could lead to PRP designation. The Company has also been named a PRP at
one site under state law. 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 activities were 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. Although liability is joint and
several, typically many parties are named as PRPs for each site and 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. If significant cleanup costs are
attributed to AEP in the future, results of operations, cash flows and
possibly financial condition would be adversely affected unless the costs
can be recovered from customers.
The Clean Air Act Amendments (CAAA) required Federal EPA to issue
rules to implement the law. In 1996 Federal EPA issued final rules
governing NOx emissions that must be met after January 1, 2000 (Phase II
of CAAA). The final rules required 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 installed NOx emission control
equipment on certain units and switched fuel at other units. The Company
is operating under the Phase II rules which require reporting at the end
of each year. The Company does not anticipate any material problems
complying with the rules.
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 U.S., 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 U.S.
Senate for ratification, would require the U.S. to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012. Although
the U.S. 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,
methodologies and guidelines of the treaty's emissions trading and 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 November 2000. We will
continue to work with the Administration and Congress to develop
responsible public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs for the Company
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. It is management's belief, that the Kyoto protocol is
unlikely to be ratified or implemented in the U.S. in its current form.
Costs for Spent Nuclear Fuel and Decommissioning
AEP, as the owner of the Cook Plant, like other nuclear power plants,
has a significant future financial commitment to safely dispose of 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 the Company participates
in the Department of Energy's (DOE) SNF disposal program which is described
in Note 6 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 permanent 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.
To date DOE has failed to comply with the requirements of the Nuclear Waste
Policy Act.
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
Appeals Court requesting, among other things, that the Appeals Court order
DOE to meet its obligations under the law. The Appeals 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 at least 2010. In 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 Plant. Similar lawsuits were filed by other utilities. On April
6, 1999, the court granted DOE's motion to dismiss a lawsuit filed by
another utility. On May 20, 1999, the other utility appealed this decision
to the U.S. Court of Appeals for the Federal Circuit. The Company's case
has been stayed pending final resolution of the other utility's appeal. 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 continue to 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 nondiscounted 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, 1999, the total
decommissioning trust fund balance was $498 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.
Year 2000 Readiness Disclosure
On or about midnight on December 31, 1999, digital computing systems
could have produced erroneous results or failed, unless these systems had
been modified or replaced, because such systems may have been programmed
incorrectly and interpreted 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 or otherwise
incorrectly interpret a year 2000 date.
The Company has not experienced any material failures of generation
and delivery of electric energy due to Year 2000 because of its
preparations. Such preparations included the modification or replacement
of certain computer hardware and software to minimize Year 2000-related
failures and repair. This included 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 was 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 sought written assurances from third parties regarding their state
of Year 2000 readiness. Another issue addressed was the impact of electric
power grid problems that may have occurred outside of our transmission
system.
Through December 31, 1999, the Company spent $46 million on its Year
2000 project. Most Year 2000 costs were for IT contractors and consultants
and for salaries of internal IT professionals and were expensed; however,
in certain cases the Company acquired hardware and new software that was
capitalized.
New Accounting Standards
The FASB issued SFAS 133 "Accounting for Derivative Instruments and
Hedging Activities" in June 1998. 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
and reviewing the Company's contracts and transactions to determine the
impact on the Company's results of operations, cash flows and financial
condition when SFAS 133 is adopted on January 1, 2001.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions - except per share amounts)
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C>
REVENUES
Domestic Regulated Electric Utility Operations $6,315 $6,346 $5,880
Worldwide Electric and Gas Operations 601 51 48
TOTAL REVENUES 6,916 6,397 5,928
OPERATING EXPENSES:
Fuel and Purchased Power 2,116 2,154 1,762
Maintenance and Other Operation 1,868 1,846 1,711
Depreciation and Amortization 600 580 591
Taxes Other Than Income Taxes 476 475 469
Worldwide Electric and Gas Operations 551 95 49
TOTAL EXPENSES 5,611 5,150 4,582
OPERATING INCOME 1,305 1,247 1,346
OTHER INCOME (net) 15 - 18
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 1,320 1,247 1,364
INTEREST AND PREFERRED DIVIDENDS 540 430 424
INCOME BEFORE INCOME TAXES 780 817 940
INCOME TAXES 260 281 320
INCOME BEFORE EXTRAORDINARY ITEM 520 536 620
EXTRAORDINARY ITEM - U.K. WINDFALL TAX - - (109)
NET INCOME $ 520 $ 536 $ 511
AVERAGE NUMBER OF SHARES OUTSTANDING 193 191 189
EARNINGS PER SHARE:
Before Extraordinary Item $2.69 $2.81 $ 3.28
Extraordinary Item - U.K. Windfall Tax - - (0.58)
Net Income $2.69 $2.81 $ 2.70
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31,
1999 1998 1997
(in millions)
Net Income $520 $536 $511
Other Comprehensive Gain (Loss) 15 (1) -
COMPREHENSIVE INCOME $535 $535 $511
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(in millions - except share data)
<CAPTION>
December 31,
1999 1998
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents $ 333 $ 173
Accounts Receivable:
Customers 553 557
Miscellaneous 369 333
Allowance for Uncollectible Accounts (12) (11)
Fuel - at average cost 307 216
Materials and Supplies - at average cost 311 280
Accrued Utility Revenues 246 214
Energy Marketing and Trading Contracts 1,001 372
Prepayments and Other 108 84
TOTAL CURRENT ASSETS 3,216 2,218
PROPERTY PLANT AND EQUIPMENT:
Electric:
Production 9,949 9,615
Transmission 3,832 3,692
Distribution 5,536 5,125
Other (including gas and coal mining assets
and nuclear fuel) 2,307 2,118
Construction Work in Progress 581 801
Total Property, Plant and Equipment 22,205 21,351
Accumulated Depreciation and Amortization 9,150 8,549
NET PROPERTY, PLANT AND EQUIPMENT 13,055 12,802
REGULATORY ASSETS 2,171 1,847
OTHER ASSETS 3,046 2,616
TOTAL $21,488 $19,483
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
<CAPTION>
December 31,
1999 1998
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable $ 699 $ 607
Short-term Debt 888 617
Long-term Debt Due Within One Year* 1,111 206
Taxes Accrued 414 382
Interest Accrued 78 75
Obligations Under Capital Leases 91 82
Energy Marketing and Trading Contracts 964 360
Other 425 472
TOTAL CURRENT LIABILITIES 4,670 2,801
LONG-TERM DEBT* 6,336 6,800
DEFERRED INCOME TAXES 2,745 2,601
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 213 222
DEFERRED INVESTMENT TAX CREDITS 326 351
DEFERRED CREDITS AND REGULATORY LIABILITIES 517 263
OTHER NONCURRENT LIABILITIES 1,511 1,429
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 164 174
COMMITMENTS AND CONTINGENCIES (Notes 6 and 7)
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
1999 1998
Shares Authorized. .600,000,000 600,000,000
Shares Issued. . . .203,103,341 200,816,469
(8,999,992 shares were held in treasury
at December 31, 1999 and 1998) 1,320 1,305
Paid-in Capital 1,932 1,854
Accumulated Other Comprehensive Income-
Foreign Currency Translation Adjustments 14 (1)
Retained Earnings 1,740 1,684
TOTAL COMMON SHAREHOLDERS' EQUITY 5,006 4,842
TOTAL $21,488 $19,483
*See Accompanying Schedules.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
<CAPTION>
Year Ended December 31,
1999 1998 1997
<S> <C> <C> <C>
OPERATING ACTIVITIES:
Net Income $ 520 $ 536 $ 511
Adjustments for Noncash Items:
Depreciation and Amortization 714 620 608
Deferred Federal Income Taxes 144 41 (7)
Deferred Investment Tax Credits (25) (25) (25)
Amortization (Deferral) of Operating
Expenses and Carrying Charges (net) (151) 15 12
Equity in Earnings of Yorkshire
Electricity Group plc (45) (38) (34)
Extraordinary Item - UK Windfall Tax - - 109
Deferred Costs Under Fuel Clause Mechanisms (116) (73) (52)
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (31) (142) (136)
Fuel, Materials and Supplies (122) 2 (1)
Accrued Utility Revenues (32) 3 (14)
Accounts Payable 92 200 147
Taxes Accrued 32 (1) (33)
Payment of Disputed Tax and Interest
Related to COLI (19) (303) (3)
Other (net) (144) 195 116
Net Cash Flows From Operating Activities 817 1,030 1,198
INVESTING ACTIVITIES:
Construction Expenditures (867) (792) (760)
Investment in Yorkshire Electricity Group plc - - (364)
Investment in CitiPower - (1,054) -
Investment in Gas Assets - (340) -
Other (47) (27) 2
Net Cash Flows Used For
Investing Activities (914) (2,213) (1,122)
FINANCING ACTIVITIES:
Issuance of Common Stock 91 86 77
Issuance of Long-term Debt 892 2,491 880
Retirement of Cumulative Preferred Stock (10) (1) (433)
Retirement of Long-term Debt (523) (915) (348)
Change in Short-term Debt (net) 271 62 235
Dividends Paid on Common Stock (464) (458) (453)
Net Cash Flows From (Used For)
Financing Activities 257 1,265 (42)
Net Increase in Cash and Cash Equivalents 160 82 34
Cash and Cash Equivalents January 1 173 91 57
Cash and Cash Equivalents December 31 $ 333 $ 173 $ 91
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
<CAPTION>
Paid-In Comprehensive Retained
(in millions) Common Stock Capital Income Earnings Total
Shares Amount
<S> <C> <C> <C> <C> <C> <C>
JANUARY 1, 1997 197 $1,282 $1,716 $- $1,548 $4,546
Issuances 2 11 66 - - 77
Retirements and Other - - (3) - - (3)
Net Income - - - - 511 511
Cash Dividends Declared - - - - (453) (453)
Foreign Currency
Translation Adjustments - - - - - -
DECEMBER 31, 1997 199 1,293 1,779 - 1,606 4,678
Issuances 2 12 74 - - 86
Retirements and Other - - 1 - - 1
Net Income - - - - 536 536
Cash Dividends Declared - - - - (458) (458)
Foreign Currency
Translation Adjustments - - - (1) - (1)
DECEMBER 31, 1998 201 1,305 1,854 (1) 1,684 4,842
Issuances 2 15 76 - - 91
Retirements and Other - - 2 - - 2
Net Income - - - - 520 520
Cash Dividends Declared - - - - (464) (464)
Foreign Currency
Translation Adjustments - - - 15 - 15
DECEMBER 31, 1999 203 $1,320 $1,932 $14 $1,740 $5,006
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
Organization - American Electric Power Company, Inc. (AEP or the
Company) is one of the United States' (U.S.) 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 energy holdings in the U.S., 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); two active coal-mining companies; a
service company, American Electric Power Service Corporation
(AEPSC); AEP Resources, Inc. (AEPR) a subsidiary which invests in,
owns and operates energy-related domestic and international
projects and companies; AEP Energy Services, Inc. (AEPES) a
non-regulated subsidiary which markets and trades energy commodities;
and other subsidiaries that provide 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, professional and other services to the AEP System
subsidiaries. The active coal-mining companies are wholly-owned by
OPCo (see Note 3 for information regarding shutdown of affiliated
mines). 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 utility company in the UK
(see Note 9); 70% of Nanyang General Light Electric Co., Ltd.,
owner of a two-unit power plant 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 supply and distribution utility.
AEPES principally markets and trades natural gas. Two non-regulated
subsidiaries, AEP Resources Service Company and AEP
Communications are engaged in providing power engineering,
consulting and management services around the world and fiber,
wireless and information communication services in the U.S.
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 1935 (1935 Act). The rates charged by the
domestic utility subsidiaries are approved by the Federal Energy
Regulatory Commission (FERC) and the state utility commissions.
The FERC regulates wholesale electricity rates and transmission
rates and the state commissions regulate retail generation and
distribution 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 with their equity earnings included in revenues from
worldwide electric and gas operations.
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 revenue) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through
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.
Property, Plant and Equipment - Property, plant and equipment are
stated at original cost of the acquirer. Additions, major
replacements and betterments are added to the plant accounts.
Retirements from the plant accounts and associated removal costs,
net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a
noncash nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated
electric utility plant. For domestic regulated electric utility
plant, it represents the estimated cost of borrowed and equity
funds used to finance construction projects. The amounts of AFUDC
for 1999, 1998 and 1997 were not significant. Worldwide operations
capitalize interest during construction in accordance with SFAS 34,
"Capitalization of Interest Costs."
Depreciation, Depletion and Amortization - Depreciation of
property, plant and equipment is provided on a straight-line basis
over the estimated useful lives of property, other than coal-mining
property, and is calculated largely through the use of composite
rates by functional class as follows:
<TABLE>
<CAPTION>
Functional Class
of Property Annual Composite Depreciation Rates Ranges
1999 1998 1997
<S> <C> <C> <C>
Production:
Steam-Nuclear 3.4% 3.4% 3.4%
Steam-Fossil-Fired 3.2% to 5.0% 3.2% to 4.4% 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.4% 2.7% to 3.4% 2.7% to 3.2%
Transmission 1.7% to 2.7% 1.7% to 2.7% 1.7% to 2.7%
Distribution 2.8% to 4.2% 3.3% to 4.2% 3.3% to 4.2%
Other 2.0% to 20.0% 2.5% to 3.8% 2.5% to 3.8%
</TABLE>
Depreciation, depletion and amortization of coal-mining assets is
provided over each asset's estimated useful life or the estimated
life of the mine, whichever is shorter, 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 $2.32 per ton in 1999, $1.85 per ton in
1998 and $1.91 per ton in 1997. These costs are included in the
cost of coal charged to fuel expense. See Note 3 regarding closure
of affiliated mines.
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 U.S. are measured using the local currency
as the functional currency. Assets and liabilities are translated
to U.S. 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. Currency
transaction gains and losses are recorded in income.
Energy Marketing and Trading Transactions - The Company makes
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 represents physical
forward electricity 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 marketing area are included in regulated
revenues for ratemaking, accounting and financial and regulatory
reporting purposes.
The Company also purchases and sells electricity and gas options,
futures and swaps, and enters into forward purchase and sale
contracts for electricity outside its traditional marketing area
and for gas. These transactions represent non-regulated trading
activities that are included in worldwide revenues.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". The EITF requires that all energy
trading contracts be marked-to-market. The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for those
open electricity trading transactions within the Company's
marketing area that are included in cost of service on a settlement
basis for ratemaking purposes in the Company's non-Virginia
jurisdictions. A Virginia jurisdiction net mark-to-market after-tax
gain of $3 million as of December 31, 1999 is included in net
income as a result of an agreed prohibition against establishing
new regulatory assets in a February 1999 Virginia State Corporation
Commission (Virginia SCC) approved settlement agreement. Non-regulated
open trading contracts are accounted for on a mark-to-market basis
and included in worldwide electric and gas operations
revenues. Unrealized mark-to-market gains and losses from all
trading activity are reported as assets and liabilities,
respectively. The adoption of the EITF did not have a material
effect on results of operations, cash flows or financial condition.
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 with the amortization included in interest
charges. There were no such forward contracts outstanding at
December 31, 1999 or 1998.
See Note 14 - Financial Instruments, Credit and Risk Management for
further discussion.
Revenues and Fuel Costs - Regulated revenues include the accrual of
electricity consumed but unbilled at month-end as well as billed
revenues. Fuel costs are matched, in accordance with SFAS 71, with
their recovery from/to customers through regulated revenues in
accordance with rate commission orders. Generally in order to
accomplish a proper matching 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 changes are
expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - In order to match
costs with regulated revenues, incremental operation and
maintenance costs associated with refueling outages at I&M's Cook
Plant are deferred commensurate with their rate-making treatment
and amortized over the period beginning with the commencement of an
outage and ending with the beginning of the next outage.
Amortization of Cook Plant Deferred Restart Costs - Pursuant to
settlement agreements approved by the Indiana Utility Regulatory
Commission (IURC) and the Michigan Public Service Commission (MPSC)
to resolve all issues related to an extended outage of the Cook
Plant, I&M deferred certain operation and maintenance costs in
1999. The settlement agreements provide for the deferral of $150
million of Indiana jurisdictional and $50 million of Michigan
jurisdictional incremental operation and maintenance costs incurred
in 1999. The deferred amount will be amortized to expense on a
straight-line basis over five years beginning January 1, 1999. I&M
deferred $200 million and amortized $40 million in 1999 leaving
$160 million as an SFAS 71 regulatory asset at December 31, 1999 on
the Consolidated Balance Sheet. See Note 2 "Nuclear Plant
Shutdown" for a discussion of the settlement agreements.
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 regulated
revenues (that is, deferred taxes are not included in the cost of
service for determining regulated rates for electricity), deferred
income taxes are recorded and related regulatory assets and
liabilities are established 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. Investment tax credits that
have been deferred are being amortized over the life of the
regulated plant investment.
Debt and Preferred Stock - Gains and losses from the reacquisition
of debt used to finance domestic regulated electric utility plant
are generally deferred and amortized over the remaining term of the
reacquired debt in accordance with their rate-making treatment. If
the debt is refinanced the reacquisition costs are generally
deferred except in Virginia and amortized over the term of the
replacement debt commensurate with their recovery in rates.
Debt discount or premium and debt issuances expenses are deferred
and amortized over the term of the related debt, with the
amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock of the
domestic utility subsidiaries 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 consistent with the timing of its recovery in rates in
accordance with SFAS 71.
Other Assets - Other assets are comprised primarily of nuclear
decommissioning and spent nuclear fuel disposal trust funds;
licenses for CitiPower operating franchises; amounts for corporate
owned life insurance and related disputed tax payments; the
investments in Yorkshire and Pacific Hydro which are accounted for
under the equity method of accounting; and goodwill. 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. Under the provisions of SFAS 71, 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. The
recoverability of goodwill (evaluated on the basis of undiscounted
operating cash flow analysis) is reviewed when events or changes in
circumstances indicate that the carrying amount may exceed fair
value.
EPS - Earnings per share is determined based upon the weighted
average number of shares outstanding. There are no dilutive
potential common shares. Therefore, earnings per share is the same
for basic earnings per share and diluted earnings per share.
Reclassification - Certain prior year amounts have been
reclassified to conform to current year presentation. Such
reclassification had no impact on previously reported net income.
2. Nuclear Plant Shutdown:
I&M owns and operates the two-unit 2,110 MW Cook Plant under
licenses granted by the Nuclear Regulatory Commission (NRC). I&M
shut down both units of the Cook Plant in September 1997 due to
questions regarding the operability of certain safety systems that
arose during a NRC architect engineer design inspection. The NRC
issued a Confirmatory Action Letter in September 1997 requiring I&M
to address certain issues identified in the letter. In 1998 the
NRC notified I&M that it had convened a Restart Panel for Cook
Plant and provided a list of required restart activities. In order
to identify and resolve the issues necessary to restart the Cook
units, I&M is working with the NRC and will be meeting with the
Panel on a regular basis until the units are returned to service.
In a February 2, 2000 letter from the NRC, I&M was notified that
the Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units.
I&M's plan to restart the Cook Plant units has Unit 2 scheduled to
return to service in April 2000 and Unit 1 scheduled to return to
service in September 2000. The restart plan was developed based
upon a comprehensive systems readiness review of all operating
systems at the Cook Plant. When maintenance and other work
including testing required for restart are complete, I&M will seek
concurrence from the NRC to return the Cook Plant to service. Any
issues or difficulties encountered in testing of equipment as part
of the restart process could delay the scheduled restart dates.
Replacement of the steam generator for Unit 1 will be completed
before it is returned to service. Costs associated with the steam
generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At December 31, 1999, $119 million has
been spent on the steam generator replacement.
The cost of electricity supplied to certain retail customers
increased due to the outage of the two Cook Plant nuclear units
since higher cost coal-fired generation and coal-based purchased
power is being substituted for the unavailable low cost nuclear
generation. With regulator approvals I&M's actual replacement
energy fuel costs that exceeded the costs reflected in billings
were recorded as a regulatory asset under Indiana and Michigan
retail jurisdictional fuel cost recovery mechanisms.
On March 30, 1999, the IURC approved a settlement agreement that
resolved all matters related to the recovery of replacement energy
fuel costs and all outage/restart costs and related issues during
the extended outage of the Cook Plant. The settlement agreement
provided for, among other things, a replacement fuel billing credit
of $55 million, including interest, to Indiana retail customers'
bills; the deferral of unrecovered fuel revenues accrued between
September 9, 1997 and December 31, 1999, including the billing
credit; the deferral of up to $150 million of restart related
nuclear operation and maintenance costs in 1999 above the amount
included in base rates; the amortization of the deferred fuel
revenues and non-fuel operation and maintenance cost deferrals over
a five-year period ending December 31, 2003; a freeze in base rates
through December 31, 2003; and a fixed fuel recovery charge through
March 1, 2004. The $55 million credit was applied to retail
customers' bills during the months of July, August and September
1999.
On December 16, 1999, the MPSC approved a settlement agreement for
two open Michigan power supply cost recovery reconciliation cases
which resolves all issues related to the Cook Plant extended
outage. The settlement agreement limits I&M's ability to increase
base rates and freezes the power supply cost recovery factor until
January 1, 2004; permits the deferral of up to $50 million in 1999
of jurisdictional non-fuel nuclear operation and maintenance
expenses; authorizes the amortization of power supply cost recovery
revenues accrued from September 9, 1997 to December 31, 1999 and
non-fuel nuclear operation and maintenance cost deferrals over a
five-year period ending December 31, 2003.
Expenditures to restart the Cook units are estimated to total
approximately $574 million. Through December 31, 1999, $373
million has been spent. The restart costs incurred in 1997 and
1998 were $6 million and $78 million, respectively, and were
recorded in other operation and maintenance expense. In 1999 the
costs incurred were $289 million and were recorded in accordance
with the Indiana and Michigan settlement agreements whereby $150
million and $50 million, respectively, of operation and maintenance
costs were deferred in 1999 for amortization through December 31,
2003. The amortization of the non-fuel operation and maintenance
restart cost deferrals through December 31, 1999 was $40 million.
Consequently, maintenance and other operation expenses included
$129 million of Cook restart expense for 1999. Restart costs
incurred in 2000 will be accounted for as a current period
operation and maintenance expense. At December 31, 1999, the
unamortized balance of restart related operation and maintenance
costs was $160 million and is included in the Company's regulatory
assets. Also deferred as a regulatory asset at December 31, 1999
was $150 million of fuel-related revenues.
The costs of the extended outage and restart efforts will have a
material adverse effect on future results of operations and
possibly financial condition through 2003 and on cash flows through
2000. Management believes that the Cook units will be successfully
returned to service in April and September 2000. However, if for
some unknown reason the units are not returned to service or their
return is delayed significantly it would have an even greater
adverse effect on future results of operations, cash flows and
financial condition.
3. 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 kilowatthour (kwh)
for the period June 1, 1995 through November 30, 1998. The 1995
Settlement Agreement requires for the two year period from December
1, 1998 through November 30, 2000 that coal from Central Ohio Coal
Company's Muskingum mine and Windsor Coal Company's mine be priced
at the market price for comparable quality coal. The Company is
allowed to defer the difference for future recovery. Effective
December 1, 1998 the 1992 stipulation continued to control the
recovery of fuel costs at the Gavin Plant and the ability of OPCo
to recover the costs to shut down its affiliated mines. 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 shutdown costs of its affiliated mines as well as any
fuel costs incurred above the predetermined rate and deferred for
future recovery under the agreements. These agreements will be
superseded effective January 1, 2001 by the Ohio Electric
Restructuring Act of 1999 (see Note 5).
The Muskingum coal mine which supplied all of its output to OPCo
was closed in October 1999. During 1999 efforts began to reclaim
the properties, sell or scrap all mining equipment, terminate both
capital and operating leases and perform other activities necessary
to shut down the mine. Mine reclamation activities should be
completed by December 31 2002; postremediation monitoring is
anticipated to continue for five years after completion of
reclamation.
In 1999 the Company announced that the affiliated Windsor coal mine
would close April 30, 2000. After the mine closes, efforts will
begin to reclaim the property, sell or scrap all mining equipment
and perform other activities necessary to shut down the mine.
Reclamation activities should be completed within two to three
years after shutdown.
The Company recorded mine closing costs of $45 million in 1998 for
the Muskingum mine and $48 million in 1999 for the Windsor mine.
Pursuant to terms of the 1992 and 1995 agreements, the Company
deferred accrued mine closure costs of $19 million in 1998 for the
Muskingum mine and $25 million in 1999 for the Windsor mine. Fuel
expense included $23 million and $26 million in 1999 and 1998,
respectively, of mine closure costs. At December 31, 1999, the
accrued liabilities for reclamation, mine closing costs and post
shutdown costs were $119 million for the Muskingum mine and $84
million for the Windsor mine.
Revenues and net income for the Muskingum mining operation in 1999
up to the shutdown date were $64 million and $1,000, respectively.
For the years ended December 31, 1998 and 1997 revenues and net
income from the Muskingum mining operation were $110 million and
$1,000 and $66 million and zero, respectively. For the years ended
December 31, 1999, 1998 and 1997 revenues and net income from the
Windsor mining operation were $123 million and $18,000, $65 million
and $123,000, and $69 million and $1 million, respectively.
Management believes that existing deferrals for the Ohio
jurisdictional portion of the cost of the mine shutdowns can be
deferred for future recovery through the Ohio fuel clause mechanism
under terms of the Ohio fuel clause predetermined price agreements.
At December 31, 1999 the Company has deferred $196 million under
the terms of the Ohio fuel clause predetermined price agreements.
However, since the Ohio Electric Restructuring Act of 1999 (the
Act) supersedes the agreements, the Company has filed under the
provisions of the Act for recovery of all of its generation
related regulatory assets which includes the fuel deferral at
December 31, 1999 plus the projected balance that will be deferred
for the accrual of the Meigs mine closure costs by the beginning of
the transition period, January 1, 2001. Under the provisions of
the Act the Company is seeking a total of $360 million for the
regulatory assets deferred under the above agreements through
transition rates and a post generation deregulation five year wires
charge. Unless the cost of the remaining coal production and
deferred mine shutdowns are recovered through the remaining Ohio
fuel clause rates and Ohio restructuring transition rates and/or a
post deregulation wires charge, future results of operations and
cash flows will be adversely affected.
Management intends to continue to recover from non-Ohio
jurisdictional ratepayers the non-Ohio jurisdictional portion of
the investment in and the liabilities and closing costs of the
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 $62 million
after tax at December 31, 1999.
FERC - The FERC issued orders 888 and 889 in April 1996 which
required each public utility that owns or controls interstate
transmission facilities to file an open access network and
point-to-point transmission tariff that offers services comparable
to the utility's own uses of its transmission system. The orders also
require utilities to functionally unbundle their services, by
requiring them to use their own transmission service tariffs in
making off-system and third-party sales. As part of the orders,
the FERC issued a pro-forma tariff which reflects the Commission's
views on the minimum non-price terms and conditions for
non-discriminatory transmission service. The FERC orders also allow a
utility to seek recovery of certain prudently-incurred stranded
costs that result from unbundled transmission service.
On July 9, 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain pricing
issues. The 1996 tariff incorporated transmission rates which were
the result of a settlement of a pending rate case, but which were
being collected subject to refund from certain customers who
opposed the settlement and continued to litigate the reasonableness
of AEP's transmission rates. On July 30, 1999, the FERC issued an
order in the litigated rate case which would reduce AEP's rates for
the affected customers below the settlement rate. AEP and certain
of the affected customers sought rehearing of the Commission's
Order. The Company made a provision in September 1999 for the
refund including interest.
On December 10, 1999, AEP filed a settlement agreement with the
FERC resolving the issues on rehearing of the July 30, 1999 order.
Under terms of the settlement, AEP will make refunds retroactive to
September 7, 1993 to certain customers affected by the July 30,
1999 FERC order. The refunds will be made in two payments. The
first payment was made February 2, 2000 pursuant to a FERC order
granting AEP's request to make interim refunds. The remainder will
be paid after the FERC issues a final order and approves a
compliance filing that AEP will make pursuant to the final order.
In addition, a new rate was made effective January 1, 2000, subject
to FERC approval, for all transmission service customers and a
future rate was established to take effect upon the consummation of
the AEP and Central and South West Corporation merger unless a
superseding rate is made effective prior to the merger.
West Virginia
On May 12, 1999, the Company's subsidiary, APCo, filed with the
Public Service Commission of West Virginia (WVPSC) for a base rate
increase of $50 million annually and a reduction in expanded net
energy cost (ENEC) rates of $38 million annually. On February 7,
2000, APCo and other parties to the proceeding filed a Joint
Stipulation and Agreement for Settlement (Joint Stipulation) with
the WVPSC for approval. The Joint Stipulation's main provisions
include no change in either base or ENEC rates effective January 1,
2000 from those base and ENEC rates in effect from November 1, 1996
until December 31, 1999 (these rates provide for recovery of
regulatory assets including any generation related regulatory
assets of approximately 0.5 mills per kwh); annual ENEC recovery
proceedings are suspended and deferral accounting for over or under
recovery is discontinued effective January 1, 2000; the net
cumulative deferred ENEC recovery balance as established by a WVPSC
order on December 27, 1996, which is $66 million at December 31,
1999, shall remain on the books as a regulatory liability.
However, if deregulation of generation occurs in West Virginia
(WV), APCo will use this regulatory liability to reduce
unrecoverable generation-related regulatory assets and, to the
extent possible, any additional cost or obligations that
deregulation may impose. APCo's share of any net savings from the
pending merger between AEP and Central and South West Corporation
prior to December 31, 2004 shall be retained by APCo. All cost
incurred in the merger that are allocated to APCo, whether the
merger is consummated or not, shall be fully charged to expense as
of December 31, 2004 and shall not be included in any WV rate
proceeding after that date. After December 31, 2004, any savings
related to the merger will be reflected in rates in any future rate
proceeding before the WVPSC to establish distribution rates or to
adjust rate caps during the transition to market based rates. If
deregulation of generation occurs in WV the net retained generation
related merger savings should be used to recover any generation
related regulatory assets that are not recovered under the
provisions of the Joint Stipulation and the mechanisms provided for
in the deregulation legislation and, to the extent possible, to
recover any additional costs or obligations that deregulation may
impose on APCo. Regardless of whether the net cumulative deferred
ENEC recovery balance and the net merger savings are sufficient to
offset all of APCo's generation related regulatory assets, under
the terms of the Joint Stipulation there will be no further
explicit adjustment to APCo's rates to provide for recovery of
generation-related regulatory assets beyond the above discussed
specific adjustments provided in the Joint Stipulation and the 0.5
mills per kwh wires charge in the WV Restructuring Plan (see Note
5 for discussion of WV Restructuring Plan).
4. Effects of Regulation and Phase-In Plans:
In accordance with SFAS 71 the consolidated financial statements
include regulatory assets (deferred expenses) and regulatory
liabilities (deferred revenues) recorded in accordance with
regulatory actions in order to match expenses and revenues from
cost-based rates in the same accounting period. 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. Among other things, application of SFAS 71
requires that the Company's regulated rates be cost-based and the
recovery of regulatory assets probable. Management has reviewed
all the evidence currently available and concluded that the Company
continues to meet the requirements to apply SFAS 71. In the event
a portion of the Company's business no longer met those
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. (See Note 5 "Restructuring Legislation".)
Recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
1999 1998
(in millions)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,278 $1,324
Deferred Fuel Costs 424 193
Unamortized Loss on Reacquired Debt 84 91
Other 385 239
Total Regulatory Assets $2,171 $1,847
Regulatory Liabilities:
Deferred Investment Tax Credits $326 $351
Other Regulatory Liabilities* 300 148
Total Regulatory Liabilities $626 $499
* Included in Deferred Credits and Regulatory Liabilities on
Consolidated Balance Sheets.
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 amortization and recovery of the deferred
Rockport Plant Unit 1 phase-in plan costs were $11.9 million.
During the recovery period net income was unaffected by the
recovery of the phase-in deferrals.
5. Restructuring Legislation:
Ohio
The Ohio Electric Restructuring Act of 1999 (the Act) became law in
October 1999. The Act provides for customer choice of electricity
supplier, a residential rate reduction of 5% for the generation
portion of rates and a freezing of generation rates including fuel
rates beginning on January 1, 2001. The Act also provides for a
five-year transition period to move from cost based rates to market
pricing for generation services. It authorizes the Public
Utilities Commission of Ohio (PUCO) to address certain major
transition issues including unbundling of rates and the recovery of
transition costs. Under the Act, transition costs can include
regulatory assets, generating asset impairments and other stranded
costs, employee severance and retraining costs, consumer education
costs and other costs. Stranded generation costs are those costs
of generation above the market price for electricity that
potentially would not be recoverable in a competitive market.
Retail electric services that will be competitive are defined in
the Act as electric generation service, aggregation service and
power marketing and brokering. Under the legislation the PUCO is
granted broad oversight responsibility and is required by the Act
to promulgate rules for competitive retail electric generation
service and transition plan filings. The Act also gives the PUCO
authority to approve a transition plan for each electric utility
company and sets a deadline of no later than October 31, 2000 for
those approvals.
The Act provides Ohio electric utilities with an opportunity to
recover PUCO approved allowable transition costs through generation
rates paid through December 31, 2005 by customers who do not switch
generation suppliers and through a transition charge for customers
who switch generation suppliers. Recovery of the regulatory asset
portion of transition costs can, under certain circumstances,
extend beyond the five-year transition period but cannot continue
beyond December 31, 2010.
The Act also provides for a reduction in property tax assessments,
the imposition of franchise and income taxes, and the replacement
of a gross receipts tax with a kwh based excise tax. The property
tax assessment percentage on generation property will be lowered
from 100% to 25% of value effective January 1, 2001 and electric
utilities will become subject to the Ohio Corporate Franchise Tax
and municipal income taxes on January 1, 2002. The last year for
which electric utilities will pay the excise tax based on gross
receipts is the tax year ending April 30, 2002. As of May 1, 2001
electric distribution companies will be subject to an excise tax
based on kwh sold to Ohio customers. The gross receipts tax is
paid at the beginning of the tax year, deferred as a prepaid
expense and amortized to expense during the tax year pursuant to
the tax law whereby the payment of the tax results in the privilege
to conduct business in the year following the payment of the tax.
The change in the tax law to impose an excise tax based on kwh sold
to Ohio customers commencing before the expiration of the gross
receipts tax privilege period will result in a 12 month period when
electric utilities are recording as an expense both the gross
receipts tax and the excise tax. In the Company's Ohio transition
plan filings, recovery of $90 million was sought for this overlap
of the gross receipts and excise taxes.
The Company filed its transition plan for OPCo and CSPCo (its Ohio
jurisdictional subsidiaries) with the PUCO on December 30, 1999.
The filings included the following elements:
a rate unbundling plan including tariff terms and conditions
necessary for restructuring,
a corporate separation plan,
an application for transition revenues,
a plan for independent operation of transmission facilities
and
other components for the implementation of restructuring.
Under the rate unbundling plan in the transition plan filing, the
Company's Ohio retail jurisdictional companies will offer two
transition period tariffs beginning January 1, 2001, the standard
tariff and the open access distribution tariff. The proposed
standard tariff applies to customers who do not choose an
alternative energy supplier. This tariff schedule includes
detailed charges for generation, transmission and distribution and
riders to fund universal service, to promote energy efficiency and
to recover regulatory assets and taxes. Taxes include charges for
municipal income, excise and franchise taxes and tax credits for
gross receipts and property taxes. For customers who choose an
alternative electric supplier, the proposed open access
distribution tariff will apply. This tariff includes charges for
transmission and distribution and riders to fund universal service,
to promote energy efficiency and to recover regulatory assets and
taxes. These riders are the same as those in the standard tariff
except there is no property tax credit.
The corporate separation plan contains proposals for each of the
Company's Ohio jurisdictional companies to establish separate
subsidiaries to own and operate their transmission and distribution
assets. The separation plan will be implemented in a manner that
recognizes the current overlap of financing arrangements. This
would permit an orderly and economically efficient separation of
each operating company so that additional transition costs can be
avoided from premature unwinding of existing financial instruments.
Prior to the actual legal separation, the Ohio jurisdictional
companies will functionally separate generation from transmission
and distribution.
An application to receive transition revenues was included in the
transition plan filing. It requests recovery of stranded
generation costs over a five year period and recovery of
generation-related regulatory assets of $974 million over a 10-year
period. The amount requested for recovery of regulatory assets
includes current and new regulatory assets including those arising
from compliance with the Act and closure of the affiliated mines.
Included in the transition plan is a proposal to implement
independent operation of the transmission system. The Company
proposes to join a regional transmission organization whose
approval is currently pending before the FERC.
A project timeline for activities to implement operational support
systems and other technical implementation issues to arrive at and
support a competitive electricity market are included in the
transition plan.
The Company plans to provide severance, retraining, early
retirement, retention, outplacement and other assistance for
displaced employees. At this time no employees are identified as
affected by electric utility restructuring. Consequently, recovery
of such costs was not requested in transition revenues as filed
with the transition plan.
The transition plan includes a consumer education plan which will
be implemented in conjunction with other electric utilities and the
PUCO staff. The transition plan also has terms and conditions for
changing suppliers and the commitment of time a customer must
accept in a service contract which are two features necessary to
accommodate restructuring.
A proposed shopping incentive in the transition plan represents the
lower of the market price or the unbundled generation rate in
current tariff schedules.
As discussed in Note 4, "Effects of Regulation and Phase-In Plans,"
the Company defers as regulatory assets and liabilities certain
expenses and revenues consistent with the regulatory process in
accordance with SFAS 71. Management has concluded that as of
December 31, 1999 the requirements to apply SFAS 71 continue to be
met since the Company's rates for generation will continue to be
cost-based regulated until the PUCO takes action on the transition
plan and the proposed tariff schedules contained in it as provided
in the Act. The establishment of rates and charges under the
transition plan should enable the Company to determine its ability
to recover regulatory assets, transition costs and other stranded
costs, a requirement to discontinue application of SFAS 71.
When the transition plan and tariff schedules are approved, the
application of SFAS 71 will be discontinued for the Ohio retail
jurisdictional portion of the generation business. At that time
the Company will have to write-off its Ohio jurisdictional
generation-related regulatory assets to the extent that they cannot
be recovered under the tariff schedules in the transition plan
approved by the PUCO and record any asset impairments in accordance
with SFAS 121, "Accounting for the Impairment of Long-lived Assets
and for Long-lived Assets to Be Disposed Of." An impairment loss
would be recorded to the extent that the cost of generation assets
cannot be recovered through generation-related revenues during the
transition period and future market prices. Until the PUCO
completes its regulatory process and issues an order related to the
Company's transition plan, it is not possible for management to
determine if any of the Company's generating assets are impaired in
accordance with SFAS 121. The amount of regulatory assets recorded
on the books at December 31, 1999 applicable to the Ohio retail
jurisdictional generating business is $666 million before related
tax effects. Due to the planned closing of affiliated mines and
other anticipated events, generation-related regulatory assets as
of December 31, 2000 allocable to the Ohio retail jurisdiction are
estimated to exceed $800 million, before income tax effects.
Recovery of these regulatory assets and an estimated asset
impairment are being sought as a part of the Company's Ohio
transition plan filing.
A determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating
assets and any loss from a possible inability to recover Ohio
generation-related regulatory assets and other transition costs
cannot be made until the PUCO takes action on the Company's
transition plan. Management is seeking full recovery of
generation-related regulatory assets, stranded costs and other
transition costs in its transition plan filing. The PUCO is
required to complete its regulatory process including review of the
Company's transition plan filing and issue a transition order no
later than October 31, 2000. Should the PUCO fail to fully approve
the Company's transition plan and its tariff schedules which
include recovery of the Company's generation-related regulatory
assets, stranded costs and other transition costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
Virginia
In March 1999 a law was enacted in Virginia to restructure the
electric utility industry. Under the restructuring law a
transition to choice of electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia SCC that an effective competitive market
exists, on January 1, 2004.
The law also provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the
Virginia law for net stranded cost recovery are: a capping of rates
until as late as July 1, 2007, and the application of a wires
charge upon customers who depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.
Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met. The Company's
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates and the wires
charge as provided in the law. The establishment of capped rates
and the wires charge should enable management to determine its
ability to recover stranded costs, a requirement to discontinue
application of SFAS 71.
When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdictional portion of the Company's generating
business. At that time the Company will have to write-off its
generation-related regulatory assets to the extent that they cannot
be recovered under the capped rates and wire charges approved by
the Virginia SCC under the provisions of the restructuring law and
record any asset impairments in accordance with SFAS 121. An
impairment loss would be recorded to the extent that the cost of
impaired assets cannot be recovered through generation-related
revenues during the transition period and future market prices.
Absent the determination through the regulatory process, wires
charges and other pertinent information of capped rates as required
by the restructuring law, it is not possible at this time for
management to determine if any generation-related assets are
impaired in accordance with SFAS 121 and if generation-related
regulatory assets will be recovered. The amount of regulatory
assets recorded on the books applicable to the Company's Virginia
retail generating business at December 31, 1999 is estimated to be
$64 million before related tax effects.
Should it not be possible under the Virginia law to recover all or
a portion of the generation-related regulatory assets and/or
tangible generating assets, it could have a material adverse impact
on results of operations and cash flows. An estimated
determination of whether the Company will experience any asset
impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation-related regulatory assets and other transition costs
cannot be made until such time as the Company completes economic
studies to estimate an asset impairment and until the transition
period capped rates and the wires charge are determined under the
law, which is expected to occur by the fourth quarter of 2000.
West Virginia
On January 28, 2000, the WVPSC issued an order approving an
electricity restructuring plan for West Virginia. The
restructuring plan has been submitted to the West Virginia
Legislature for approval or rejection which is expected to occur
during the current legislative session that ends in March 2000.
Until approved by the West Virginia Legislature, the restructuring
plan cannot take effect. The Company's subsidiaries, APCo and
WPCo, which do business in West Virginia, will be affected by the
proposed restructuring.
The provisions of the proposed restructuring plan provide for
customer choice to begin on January 1, 2001, or at a later date set
by the WVPSC after all necessary rules are in place (the "starting
date"); deregulation of generation assets occurring on the starting
date; functional separation of the generation, transmission and
distribution businesses on the start date and their legal corporate
separation no later than January 1, 2005; a transition period of up
to 13 years, during which the incumbent utility must provide
default service for customers who do not change suppliers unless an
alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13 year transition
period as discussed below; deregulation of metering and billing; a
0.5 mills per kwh wires charge applicable to all retail customers
for the period January 1, 2001 through December 31, 2010 intended
to provide for recovery of any stranded cost including net
regulatory assets; establishment of a rate stabilization deferred
balance by AEP of $81 million by the end of year ten of the
transition period to be used as determined by the WVPSC to offset
prices paid in the eleventh, twelfth, and thirteenth year of the
transition period by residential and small commercial customers
that do not choose a supplier.
Default rates for residential and small commercial customers are
capped for four years after the starting date and then increased as
specified in the plan for the next six years. In years eleven,
twelve and thirteen of the transition period, the power supply rate
shall equal the market price of comparable power. Default rates
for industrial and large commercial customers are discounted by 1%
for four and a half years, beginning July 1, 2000, and then
increased at pre-defined levels for the next three years. After
seven years the power supply rate for industrial and large
commercial customers will be market based.
Management has concluded that as of December 31, 1999 the
requirements to apply SFAS 71 continue to be met. The Company's
West Virginia rates for generation will continue to be cost-based
regulated until the West Virginia Legislature approves the
restructuring plan. At that time, management should be able to
determine its ability to recover stranded costs, a requirement to
discontinue application of SFAS 71.
When the restructuring plan is enacted into law, the application of
SFAS 71 will be discontinued for the West Virginia retail
jurisdictional portion of the Company's generating business. At
that time the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be recovered under
the provisions of the approved restructuring plan and record any
asset impairments in accordance with SFAS 121. An impairment loss
would be recorded to the extent that the cost of impaired assets
cannot be recovered through generation-related revenues during the
transition period and future market prices. Absent the approval
through the regulatory and legislative processes of rates and other
pertinent information, it is not possible at this time for
management to determine if any generation-related assets are
impaired in accordance with SFAS 121 and if generation-related
regulatory assets will be recovered. The amount of regulatory
assets recorded on the books applicable to the Company's West
Virginia retail generating business at December 31, 1999 is
estimated to be $131 million before related tax effects.
Should it not be possible under the West Virginia restructuring
plan to recover all or a portion of the generation-related
regulatory assets and/or tangible generating assets, it could have
a material adverse impact on results of operations and cash flows.
An estimated determination of whether the Company will experience
any asset impairment loss regarding its West Virginia retail
jurisdictional generating assets and any loss from a possible
inability to recover generation-related regulatory assets and other
transition costs cannot be made until such time as the Company
completes economic studies to estimate an asset impairment and
until the West Virginia Legislature approves the restructuring plan
and the WVPSC approves the Joint Stipulation (See Note 3), which
are both expected to occur in March 2000.
6. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial
construction commitments to support its utility operations.
Aggregate construction expenditures for 2000-2002 for consolidated
domestic and foreign operations are estimated to be $2.8 billion.
Long-term contracts to acquire fuel for electric generation have
been entered into for various terms, the longest of which extends
to the year 2014. The contracts provide for periodic price
adjustments 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 1,275 MW of
capacity domestically on a long-term basis to unaffiliated
utilities. Certain of these contracts totaling 250 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 2000 to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 MW Cook
Plant under licenses granted by the 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 U.S., 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 would be adversely affected.
Nuclear Incident Liability - Public liability is limited by law to
$9.9 billion should an incident occur at any licensed reactor in
the U.S. Commercially available insurance provides $200 million of
coverage. In the event of a nuclear incident at any nuclear plant
in the U.S. the remainder of the liability would be provided by a
deferred premium assessment of $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 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
kwh for fuel consumed after April 6, 1983 is being collected from
customers and remitted to the U.S. Treasury. Fees and related
interest of $199 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, 1999, funds collected from customers towards payment of the
pre-April 1983 fee and related earnings thereon are in trust funds
and 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 estimated
cost of 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 a noncurrent liability
equal to the decommissioning cost recovered in rates; such amounts
were $28 million in 1999, $29 million in 1998 and $28 million in
1997. Decommissioning costs recovered from customers are deposited
in external trusts. In 1999 the Company also deposited in the
decommissioning trust $4 million related to a special regulatory
commission approved funding method. Trust fund earnings increase
the fund assets and the recorded liability and decrease the amount
needed to be recovered from ratepayers. During 1999 and 1998 I&M
withdrew $8 million and $3 million, respectively, from the trust
fund for decommissioning of the original steam generators removed
from Unit 2. At December 31, 1999 and 1998, I&M has recognized a
decommissioning liability of $501 million and $446 million,
respectively.
Federal EPA Complaint and Notice of Violation - Under the Clean Air
Act, if a plant undertakes a major modification that directly
results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional
pollution control technology. This requirement does not apply to
activities such as routine maintenance, replacement of degraded
equipment or failed components, or other repairs needed for the
reliable, safe and efficient operation of the plant.
On November 3, 1999 the Department of Justice, at the request of
the U.S. Environmental Protection Agency (Federal EPA), filed a
complaint in the U.S. District Court for the Southern District of
Ohio that alleges the Company made modifications to generating
units at certain of its coal-fired generating plants over the
course of the past 25 years that extend unit operating lives or
increase unit generating capacity without a preconstruction permit
in violation of the Clean Air Act. Federal EPA also issued Notices
of Violation to the Company alleging similar violations at certain
AEP plants. A number of unaffiliated utilities also received
Notices of Violation, complaints or administrative orders.
The states of New Jersey, New York and Connecticut were
subsequently granted leave to intervene in the Federal EPA's action
against the Company under the Clean Air Act. On November 18, 1999
a number of environmental groups filed a lawsuit against power
plants owned by the Company alleging similar violations to those in
the Federal EPA complaint and Notices of Violation. This action
has been consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per
day per violation at each generating unit ($25,000 per day prior to
January 30, 1997). Civil penalties, if ultimately imposed by the
court, and the cost of any required new pollution control
equipment, if the court accepts Federal EPA's contentions, could be
substantial.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to
vigorously pursue its defense of this matter.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and where states are deregulating generation, unbundled
transition period generation rates, wires charges and future market
prices for energy.
COLI 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 (COLI) program should not be allowed. As a result
of a suit filed in U.S. 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, 1999 would reduce earnings
by approximately $317 million (including interest).
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-98 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 consolidated balance sheet in other assets pending
the resolution of this matter. The Company is seeking refund
through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District
of Ohio in March 1998. In 1999 a U.S. Tax Court judge decided in
the Winn-Dixie Stores v. Commissioner case that a corporate
taxpayer's COLI interest deduction should be disallowed.
Notwithstanding the decision in Winn-Dixie management has made no
provision for any possible adverse earnings impact from this matter
because it believes, and has been advised by outside counsel, that
it has a meritorious position and will vigorously pursue its
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.
Other - The Company is involved in a number of other legal
proceedings and claims. While management is unable to predict the
ultimate outcome of these matters, it is not expected that their
resolution will have a material adverse effect on the results of
operations, cash flows or financial condition.
7. Subsequent Event - NOx Reductions (March 3, 2000):
On March 3, 2000, the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court) issued a decision generally
upholding Federal EPA's final rule (the NOx rule) that requires
substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including the states in which the Company's
generating plants are located. A number of utilities, including the
Company, had filed petitions seeking a review of the final rule in
the Appeals Court. On May 25, 1999, the Appeals Court had
indefinitely stayed the requirement that states develop revised air
quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003.
On April 30, 1999, Federal EPA took final action with respect to
petitions filed by eight northeastern states pursuant to the Clean
Air Act (Section 126 Rule). The rule approved portions of the
states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx Rule. The AEP System companies
with generating plants, as well as other utility companies, filed
a petition in the Appeals Court seeking review of Federal EPA's
approval of the northeastern states' petitions. In 1999, three
additional northeastern states and the District of Columbia filed
petitions with Federal EPA similar to those originally filed by the
eight northeastern states. Since the petitions relied in part on
compliance with an 8-hour ozone standard remanded by the Appeals
Court in May 1999, Federal EPA indicated its intent to decouple
compliance with the 8-hour standard and issue a revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126 Rule
not based on the 8-hour standard and ordered 392 industrial
facilities, including certain coal-fired generating plants owned by
the Company, to reduce their NOx emissions by May 1, 2003. This
rule approves portions of the petitions filed by four northeastern
states which contend that their failure to meet Federal EPA smog
standards is due to emissions from upwind states' industrial and
coal-fired generating facilities.
Preliminary estimates indicate that compliance with the NOx rule
upheld by the Appeals Court could result in required capital
expenditures of approximately $1.6 billion for the Company. Since
compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or
reflected in the future market price of electricity if generation
is deregulated, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition.
8. Proposed Merger:
The Company and Central and South West Corporation (CSW) announced
plans to merge in December 1997. The appropriate shareholder
proposals for the consummation of the merger were approved in 1998.
Both companies have mutually agreed to extend the closing of the
merger available in the original 1997 agreement to gain the final
regulatory approvals. The amendment to the merger agreement
requires that the companies close the merger before June 30, 2000.
The merger has already received approval from state regulatory
commissions in Arkansas, Louisiana, Oklahoma and Texas, the four
states within CSW's service territory which are required to approve
the merger. AEP has reached agreements with its state regulatory
commission in Indiana, Michigan, Ohio and Kentucky. These AEP
service territory state commissions have agreed not to oppose the
merger in federal proceedings. In addition, the Nuclear Regulatory
Commission has approved a license transfer application for the
transfer of control of CSW subsidiary Central Power and Light's
South Texas Nuclear Plant to the Company and the Department of
Justice closed its investigation under the Hart-Scott-Rodino
Antitrust Improvements Act. Also, in 1998 the FERC issued an order
which confirmed that a 250 MW firm contract path with the Ameren
System was available. The contract path was obtained by the
Company 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.
The merger requires additional approvals by the FERC and the SEC.
On July 29, 1999 applications were made with the Federal
Communication Commission to authorize the transfer of control of
licenses of several CSW entities to the Company.
FERC
In November, 1998 the FERC issued an order establishing hearing
procedures for the merger. The 1998 FERC order indicated that the
review of the proposed merger will address the issues of
competition, market power and customer protection. On May 25, 1999
AEP and CSW reached a settlement with the FERC trial staff
resolving competition and rate issues relating to the merger. On
July 13, 1999 AEP and CSW reached an additional settlement with the
FERC trial staff resolving additional issues. The settlements were
submitted to the FERC for approval. Under the terms of the
settlements, AEP filed with the FERC a regional transmission
organization (RTO) proposal whereby it will transfer the operation
and control of AEP's bulk transmission facilities to an RTO. The
settlements also cover rates for transmission services and
ancillary service as well as resolve issues related to system
integration agreements and confirm, subject to FERC guidance on
certain elements, that the proposed generation divestiture of up to
550 megawatts of capacity will satisfy the staff's market power
concerns. FERC hearings began on June 29, 1999 and concluded on
July 19, 1999.
On June 28, 1999, the Company and CSW filed a motion asking the
FERC to waive the requirement for a post-hearing decision by an
administrative law judge (ALJ) who presides over the merger
hearing. The motion indicated that the commission could then
decide the matter based on the hearing record and briefs submitted
by all interested parties. On July 28, 1999, the FERC ordered the
ALJ to issue an initial decision as soon as possible, but no later
than November 24, 1999. The commission concluded that it needed
the benefit of the ALJ's opinion and, therefore, decided not to
grant the request. The administrative law judge who presided over
the FERC merger hearing filed an initial decision with the
commission on November 23 1999 and found the AEP-CSW merger to be
in the public interest. The FERC indicated it will act on the
merger no later than February or March 2000.
Arkansas
On December 17, 1998, the Arkansas Commission approved a stipulated
agreement related to a proposed merger regulatory plan. The
stipulated agreement calls for CSW's Arkansas operating subsidiary,
Southwestern Electric Power Company to share net merger savings
with its retail customers through a net merger savings rate
reduction rider of $6 million over the five-year period following
completion of the merger.
Louisiana
In September, 1999 the Louisiana Public Service Commission (LPSC)
issued a final order granting approval of the pending merger
between the Company and CSW. In granting approval, the LPSC also
approved a stipulated settlement in which the Company and CSW
agreed to share with SWEPCO's Louisiana customers net merger
savings created as a result of the merger over the eight years
following its consummation. The net merger savings are estimated
to total more than $18 million during that eight-year period. In
addition the settlement also includes a cap on base rates for five
years after consummation of the merger; sharing of benefits from
off-system sales; establishment of conditions for affiliate
transactions with other AEP and CSW subsidiaries; provisions to
ensure continued quality of service; and provisions to hold
SWEPCO's Louisiana customers harmless for adverse effects of the
merger, if any.
Oklahoma
On May 11, 1999, the Oklahoma Corporation Commission (OCC) approved
the proposed merger between the Company and CSW. The approval
follows an administrative law judge's oral decision on a partial
settlement between certain principal parties to the Oklahoma merger
proceeding which recommended that the OCC approve the merger. The
partial settlement provides for sharing of net merger savings with
Oklahoma customers; no increase in Oklahoma base rates prior to
January 1, 2003; filing by December 31, 2001 with the FERC an
application to join a regional transmission organization; and
implementing additional quality of service standards for Oklahoma
retail customers. Oklahoma's share (approximately $50 million) of
net merger savings over the first five years after the merger is
consummated will be shared between Oklahoma customers and AEP
shareholders. The partial settlement agreement includes a
recommendation by the OCC staff that the OCC file with FERC
indicating that it does not oppose the merger, but reserves the
right to ensure that there are no adverse impacts on the Oklahoma
transmission system from the FERC's approval order. Certain
municipal and cooperative customers appealed the OCC's merger
approval order. On October 13, 1999 this appeal was dismissed by
the Oklahoma Supreme Court and the municipal and cooperative
customers have since asked the OCC to withdraw or dismiss their
appeal.
Texas
On May 4, 1999, AEP and CSW announced that a stipulated settlement
had been reached in Texas. The agreement builds upon an earlier
settlement agreement signed by AEP, CSW and certain parties to the
Texas merger proceeding. In addition to the parties that were
signatories to the earlier agreement, the staff of the Public
Utility Commission of Texas is a signatory to the new settlement as
well as other key parties to the merger proceeding. The stipulated
settlement would result in rate reductions for Texas customers
totaling $221 million over a six-year period commencing with the
merger's consummation. The rate reduction is composed of $84
million of net merger savings and $137 million to resolve existing
issues associated with CSW operating subsidiaries' rate and fuel
reconciliation proceedings in Texas. Under the terms of the
settlement agreement, base rates can not be increased before
January 1, 2003 or three years after the merger is consummated,
whichever is later. The settlement also calls for the divestiture
of a total of 1,604 megawatts of existing and proposed generating
capacity within Texas. If it is determined that the divestiture
can proceed immediately after the merger closes without
jeopardizing pooling-of-interests accounting treatment for the
merger, sale of the plants would begin no later than 90 days after
the merger closes. Absent that determination, the divestiture
would begin approximately two years after the merger closes to
satisfy the requirements to use pooling-of-interests accounting
treatment. Other provisions in the settlement agreement provide
for, among other things, accelerated stranded cost recovery,
quality-of-service standards, continuation of programs for
disadvantaged customers and transfer of control of bulk
transmission facilities to a regional transmission organization.
Hearings on the merger in Texas began August 9, 1999 and concluded
on August 10, 1999. Before the hearings began, settlements were
reached with all but one of the parties in the case. The settling
parties are all wholesale electric customers of CSW's Texas
electric operating companies. The settlements call for the
withdrawal of their opposition to the merger in all regulatory
approval proceedings. In its open meeting on November 4, 1999, the
Texas Commission approved the application on the pending merger and
the stipulated settlement announced in May.
Indiana
The IURC approved a settlement agreement related to the merger on
April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger initiated by the IURC. The
terms of the settlement agreement provide for, among other things,
a sharing of net merger savings through reductions in customers'
bills of approximately $67 million over eight years following
consummation of the merger; a one year extension through January 1,
2005 of a freeze in base rates; additional annual deposits of $6
million to the nuclear decommissioning trust fund for the Indiana
jurisdiction for the years 2001 through 2003; quality-of-service
standards; and participation in a regional transmission
organization. As part of the settlement agreement, the IURC agreed
not to oppose the merger in the FERC or SEC proceedings.
Michigan
The MPSC has approved a Settlement Agreement with the Company
related to the pending merger. In approving the Settlement
Agreement, the MPSC has agreed to not oppose the merger at the
federal level. AEP has agreed to share net merger savings with
Michigan customers as well as AEP shareowners; establish
performance standards that will maintain or improve customer
service and system reliability; join a regional transmission
organization by December 31, 2000; and establish affiliate rules to
protect consumers and promote fair competition.
The Michigan jurisdictional customers' share of the net guaranteed
merger savings is approximately $14 million over the eight years
following the consummation of the merger. Once the merger is
consummated, Michigan customers will receive their share of the
savings through credits of approximately 1 percent to 1.5 percent
every year. The credits will continue for at least eight years and
will not be affected by any changes to the current regulatory
structure in Michigan.
Kentucky
On April 15, 1999, in compliance with a request from the staff of
the Kentucky Public Service Commission (KPSC) AEP filed an
application seeking KPSC approval for the indirect change in
control of KPCo that will occur as a result of the proposed merger.
Although AEP did not believe that the KPSC has the jurisdictional
authority to approve the merger, AEP reached a merger settlement
agreement on May 24, 1999 with key parties in Kentucky which the
KPSC approved on June 14, 1999. Under the terms of the Kentucky
settlement, AEP has agreed to share net merger savings with
Kentucky customers; establish performance standards that will
maintain or improve customer service and system reliability; and to
establish rules to protect consumers and promote fair competition.
The Kentucky customers' share of the net merger savings are
expected to be approximately $28 million. The key parties to the
Kentucky settlement agreed not to oppose the merger during the FERC
or the SEC proceedings.
Ohio
On October 21, 1999, the PUCO issued a decision stating that it
will notify the FERC that it will withdraw its opposition to the
Company's pending merger with CSW and will not seek conditions on
the merger.
American Municipal Power - Ohio (AMP-Ohio) and AEP reached a
settlement addressing outstanding issues. As part of the
settlement AMP-Ohio agreed to withdraw as an intervenor in the
merger process. AMP-Ohio is the nonprofit wholesale power supplier
and service provider for most of Ohio's 84 community-owned public
power systems, two West Virginia public power systems and four
Pennsylvania public power systems.
Other
AEP and CSW have reached settlements with the Missouri Commission,
the International Brotherhood of Electrical Workers, representing
employees of AEP and CSW, and the Utility Worker's Union of America
representing AEP employees, and certain wholesale customers. All
have agreed not to oppose the merger in the FERC or SEC
proceedings.
The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (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. On
January 25, 2000 the UK's Department of Trade and Industry gave its
approval to the merger finding no competitive problems with the
ownership of two UK RECs. This final clearance was conditional on
the companies agreeing to certain assurance concerning operation of
the UK interest including meeting customer service obligations,
maintaining debt ratings of investment grade or above and separate
distribution and supply activities.
Completion of the Merger
As of December 31, 1999, AEP had deferred $42 million of
incremental costs related to the merger on its consolidated balance
sheet, which will be charged to expense if AEP and CSW are not
successful in completing their proposed merger. If the merger is
consummated the deferred costs allocable to the domestic utility
subsidiaries will be amortized over their recovery period,
generally five to eight years, in accordance with state regulator
orders. The remainder of the deferred merger costs will be
expensed upon consummation of the merger.
The merger is conditioned upon, among other things, the approval of
certain 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. To consummate the merger,
the Company needs to obtain the approval of the FERC and the SEC.
Although consummation of the merger is expected to occur in the
second quarter of 2000, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings. Also
if the merger savings do not approximate the agreed to net merger
savings rate reduction riders in the five to eight years after the
consummation of the merger, future results of operations, cash flow
and possibly financial condition could be adversely affected.
9. Acquisitions:
The Company completed two energy related acquisitions in 1998
through a subsidiary, AEPR. Both acquisitions have been accounted
for using the purchase method. One acquisition was of CitiPower,
an Australian distribution utility, that serves approximately
250,000 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 and a full year of
CitiPower's results of operations are included in the 1999
consolidated statement of income. Assets acquired and liabilities
assumed have been recorded at their fair values. Based on an
independent appraisal, $616 million of the purchase price was
allocated to retail and wholesale distribution licenses which are
being amortized on a straight-line basis over 20 years and 40
years, respectively. The excess of cost over fair value of the net
assets acquired was approximately $34 million and has been recorded
as goodwill in other assets and is being amortized on a
straight-line basis over 40 years.
The other 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. A full year of the midstream gas operations' results of
operations is included in the 1999 consolidated statement of
income. Assets acquired and liabilities assumed have been recorded
at their fair values. The excess of cost over fair value of the
net assets acquired was approximately $158 million for the
midstream gas storage operations and $17 million for the gas
trading and marketing operation and has been recorded as goodwill
in other assets and is being amortized on a straight-line basis
over 40 years and 10 years, respectively.
10. 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 $368 million and $326 million at December 31, 1999 and
1998, respectively, and is included in other assets.
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 million share of the
tax is reported as an extraordinary loss in 1997.
The 1999 and 1998 equity earnings from the Yorkshire investment are
$45 million and $39 million, respectively, and are included in
worldwide electric and gas operations revenues. Equity earnings
from the Yorkshire investment for 1997, excluding the extraordinary
loss, were $34 million.
<PAGE>
The following amounts which are not included in AEP's consolidated
financial statements represent 100% of YPG's summarized
consolidated financial information:
December 31,
1999 1998
(in millions)
Assets:
Property, Plant and Equipment $1,666 $1,602
Current Assets 450 552
Goodwill (net) 1,461 1,547
Other Assets 289 295
Total Assets $3,866 $3,996
Capitalization and Liabilities:
Common Shareholders' Equity $ 725 $ 666
Long-term Debt 2,031 2,121
Other Noncurrent Liabilities 442 414
Long-term Debt Due Within One Year 14 13
Current Liabilities 654 782
Total Capitalization and
Liabilities $3,866 $3,996
Twelve Months Ended Nine Months Ended
December 31, December 31,
(in millions)
1999 1998 1997
Income Statement Data:
Operating Revenues $2,335 $2,284 $1,493
Operating Income 301 298 202
Income Before
Extraordinary Item 90 77 68
Net Income (Loss) 90 77 (151)
In August 1999 the Office of Gas and Electricity Markets (OFGEM,
which is the UK regulator of gas and electricity rates), published
draft price proposals for the UK's regional distribution businesses
including Yorkshire and SEEBOARD that would be effective for the
five-year period beginning April 1, 2000. Under the draft price
proposals, the distribution rates for Yorkshire would be reduced
15% to 20% from current rates. Yorkshire filed comments on
September 17, 1999 with OFGEM expressing various concerns with the
analysis used by OFGEM.
On October 8, 1999, OFGEM issued updated draft price proposals for
Yorkshire's electric distribution business. The updated proposals
would require Yorkshire to reduce distribution rates 15% and
transfer 8% of costs to Yorkshire's electricity supply business, an
overall reduction in distribution prices of 23%.
Also on October 8, 1999, OFGEM issued draft price proposals for
Yorkshire's electric supply business. Under the proposals, a
supply price cap for certain domestic UK customers is retained from
April 2000 through March 2002. For Yorkshire, these proposals
would result in a price reduction of approximately 10.7% on the
standard domestic tariff commencing April 2000 and ending March
2001 and a nominal price freeze for the year commencing April 2001
and ending March 2002.
In December 1999 OFGEM issued its final proposals for both
Yorkshire's distribution and supply businesses. The final
distribution and supply price controls were substantially the same
as OFGEM's October 8, 1999 proposals except that the reduction in
the standard domestic tariff is 3.6% for the supply business. On
December 20, 1999, Yorkshire informed OFGEM of its intention to
accept the final proposals.
Yorkshire management also believes that supply prices established
in the competitive market may require Yorkshire to charge supply
prices that are lower than the maximum prices established by OFGEM
for customers Yorkshire wishes to retain and who are subject to
supply price controls. If Yorkshire charges lower supply prices,
the result will be a further reduction in supply revenues beyond
that required by OFGEM.
Yorkshire management intends to take all available opportunities to
increase revenues and reduce costs to mitigate the impact of the
final OFGEM distribution and supply price reductions. Should
Yorkshire be unable to increase revenues and reduce costs in
amounts sufficient to offset the impact of the OFGEM distribution
and supply price reductions, AEP's equity earnings from its
investment in Yorkshire will be significantly reduced in comparison
to its current level of earnings.
11. 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.
A provision for severance costs totaling $26 million was recorded
in December 1998 for reductions in power generation and energy
delivery staffs and were charged to maintenance and other operation
expense in the Consolidated Statements of Income. The power
generation and energy delivery staff reductions were made in the
first quarter of 1999. The amount of severance benefits paid was
not significantly different from the amount accrued.
<PAGE>
12. 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, 1999, and a statement of the funded
status as of December 31 for both years:
<TABLE>
<CAPTION>
Pension Plan OPEB
1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C>
Reconciliation of benefit
obligation:
Obligation at January 1 $2,126 $1,909 $1,022 $ 850
Service Cost 50 45 22 17
Interest Cost 146 133 72 59
Participant Contributions - - 7 6
Plan Amendments (a) 7 48 - -
Actuarial (Gain) Loss (253) 96 19 133
Acquisitions (b) - - - 3
Benefit Payments (109) (105) (53) (46)
Curtailments - - 10(c) -
Obligation at December 31 $1,967 $2,126 $1,099 $1,022
Reconciliation of fair value
of plan assets:
Fair value of plan assets at
January 1 $2,651 $2,370 $396 $312
Actual Return on Plan Assets 248 386 79 53
Company Contributions - - 47 72
Participant Contributions - - 6 6
Benefit Payments (109) (105) (52) (47)
Fair value of plan assets at
December 31 $2,790 $2,651 $476 $396
Funded status:
Funded status at December 31 $ 823 $ 525 $(623) $(626)
Unrecognized Net Transition
(Asset) Obligation (39) (49) 317 361
Unrecognized Prior-Service Cost 146 157 - -
Unrecognized Actuarial
(Gain) Loss (1,042) (757) 179 175
Accrued Benefit Liability $ (112) $(124) $(127) $ (90)
(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.
(c) Related to the October 31, 1999 shutdown of Central Ohio Coal Company's
Muskingum mine and the anticipated April 30, 2000 shutdown of the Windsor Coal
Company mine. Both companies are subsidiaries of AEP.
<PAGE>
The following table provides the amounts recognized in the
consolidated balance sheets as of December 31 of both years:
</TABLE>
<TABLE>
<CAPTION>
Pension Plan OPEB
1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C>
Accrued Benefit Liability $(112) $(124) $(127) $(90)
Additional Minimum Liability (8) (3) - -
Intangible Asset 8 3 - -
Net Amount Recognized $(112) $(124) $(127) $(90)
</TABLE>
The Company's nonqualified pension plan had an accumulated benefit
obligation in excess of plan assets of $29 million and $25 million
at December 31, 1999 and 1998, respectively. There are no plan
assets in the nonqualified plan.
The Company's OPEB plans had accumulated benefit obligations in
excess of plan assets of $623 million and $626 million at December
31, 1999 and 1998, respectively.
<TABLE>
The following table provides the components of net periodic benefit
cost for the plans for fiscal years 1999, 1998 and 1997:
<CAPTION>
Pension Plan OPEB
1999 1998 1997 1999 1998 1997
(in millions)
<S> <C> <C> <C> <C> <C> <C>
Service cost $ 50 $ 45 $ 36 $ 22 $ 17 $ 14
Interest cost 146 133 129 72 59 55
Expected return
on plan assets (201) (172) (154) (36) (28) (22)
Amortization of
transition
(asset) obligation (10) (10) (10) 32 32 32
Amortization of
prior-service
cost 18 14 14 - - -
Amortization of
net actuarial
(gain) loss (15) (2) (5) 5
Net periodic
benefit cost (12) 8 10 95 80 79
Curtailment loss(a) - - - 18 24 -
Net periodic
benefit
cost after
curtailments $(12) $ 8 $ 10 $113 $104 $79
(a) Curtailment charges were recognized during 1999 and 1998 for the October 31,
1999 shutdown of Central Ohio Coal Company's Muskingum mine and the anticipated
April 30, 2000 shutdown of the Windsor Coal Company mine. Both companies are
subsidiaries of AEP.
<PAGE>
The assumptions used in the measurement of the Company's benefit
obligation are shown in the following table:
</TABLE>
<TABLE>
Pension Plan OPEB
1999 1998 1997 1999 1998 1997
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
Weighted-average
assumptions
as of December 31
Discount rate (a) 8.00% 6.75% 7.00% 8.00% 6.75% 7.00%
Expected return on plan
assets 9.00% 9.00% 9.00% 8.75% 8.75% 8.75%
Rate of compensation
increase 3.2% 3.2% 3.2% N/A N/A N/A
(a) The 1999 expense was re-measured as of July 31, 1999 using a discount rate
of 7.50%.
</TABLE>
For measurement purposes, a 5.5% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 2000.
The rate was assumed to decrease gradually each year to a rate of
5.0% 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:
1% Increase 1% Decrease
(in millions)
Effect on total of service and
interest cost components of
net periodic postretirement
health care benefit cost $ 12 $ (10)
Effect on the health care
component of the accumulated
postretirement benefit obligation 123 (109)
CitiPower, a subsidiary acquired on December 31, 1998 sponsors a
defined benefit pension plan. At December 31, 1999 and 1998, the
fair value of the plan assets was $30 million and $25 million,
respectively, and the accumulated benefit obligation of this plan
was $27 million and $25 million, respectively. 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 $21 million in 1999 and 1998 and
$20 million in 1997.
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 1999, 1998 and 1997. Based upon the UMWA
actuary estimate, the Company's share of unfunded pension liability
was $17 million at June 30, 1999. 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
the pension plan that equals the unfunded pension liability. If
the Meigs mining operations had been closed on December 31, 1999
the estimated annual liability for the UMWA health and welfare
plans would have been approximately $1 million.
13. Business Segments:
As of December 31, 1998, the Company adopted SFAS 131, "Disclosure
about Segments of an Enterprise and Related Information." SFAS 131
establishes 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
cost-based 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 accounting policies of the reportable segments are
the same as those described in Note 1, "Significant Accounting
Policies."
The Company's principal business segment is its cost-based rate
regulated domestic regulated electric utility operations consisting
of seven domestic regulated utility subsidiaries 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 in the Company's
traditional marketing area as part of regulated operations and
subject to regulatory ratemaking oversight.
The worldwide electric and gas operations segment is principally
made up of international investments in energy-related projects and
operations. It also includes the acquisition, development and
management of electricity and gas projects and operations
worldwide. Such investment activities include electric generation,
supply and distribution, and natural gas pipeline, storage and
other natural gas services. Although the businesses in the
worldwide operations segment are generally subject to different
forms of price regulation, they are not cost-based rate regulated.
As a result for reporting purposes under U.S. generally accepted
accounting principles they do not record regulatory assets and
liabilities in accordance with SFAS 71. The other operations
business segment includes electric trading outside the Company's
traditional marketing area, gas trading operations,
telecommunication services, and the marketing of various energy
related products and services. As of December 31, 1999 and 1998,
less than 6% of consolidated long-lived assets were located in
foreign countries.
<TABLE>
<CAPTION>
Domestic Regulated Worldwide Elimination
Electric Utility Electric and Other Reconciling AEP
Year Operations Gas Operations Operations Adjustments Consolidated
(in millions)
<S> <C> <C> <C> <C> <C>
1999
Revenues from
external unaffiliated
customers $6,315 $722* $(121) - $6,916
Revenues from transactions
with other operating
segments - 72 143 $(215) -
Interest expense 412 109 7 - 528
Depreciation, depletion and
amortization expense 600 55 5 (60) 600
Income tax expense (benefit) 316 (39) (17) - 260
Segment net income (loss) 508 41 (29) - 520
Total assets 18,038 2,482 968 - 21,488
Investments in equity method
subsidiaries - 433 - - 433
Gross property additions 735 114 18 - 867
1998
Revenues from
external unaffiliated
customers $6,346 $94* $(43) - $6,397
Revenues from transactions
with other operating
segments - 2 14 $(16) -
Interest expense 399 17 3 - 419
Depreciation, depletion and
amortization expense 580 1 1 (2) 580
Income tax expense (benefit) 317 (15) (21) - 281
Segment net income (loss) 564 12 (40) - 536
Total assets 16,837 2,063 583 - 19,483
Investments in equity method
subsidiaries - 335 - - 335
Gross property additions 700 1,463 23 - 2,186
1997
Revenues from
external unaffiliated
customers $5,880 $48* $ - $ - $ 5,928
Revenues from transactions
with other operating
segments - - - - -
Interest expense 390 15 1 - 406
Depreciation, depletion and
amortization expense 591 - - - 591
Income tax expense (benefit) 352 (25) (7) - 320
Extraordinary Loss -
UK Windfall Tax - (109) - - (109)
Segment net income (loss) 603 (80) (12) - 511
Total assets 16,224 367 24 - 16,615
Investments in equity method
subsidiaries - 287 - - 287
Gross property additions 694 62 4 - 760
* Worldwide electric and gas revenues for the years ended December 31, 1999 and 1998 include net
income from subsidiaries accounted for under the equity method of $45 million and $39 million,
respectively. For the year ended December 31, 1997 worldwide electric and gas revenues include $34
million of earnings excluding an extraordinary loss from subsidiaries accounted for under the equity
method.
</TABLE>
14. 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 wholesale electricity and gas trading and
marketing operations that manage 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 within AEP's traditional
economic market area are recorded on a net basis as domestic
regulated electric utility operations revenues in the month when
the physical contract settles. Physical forward electricity
contracts outside AEP's traditional marketing area, and all
financial electricity trading transactions where the underlying
physical commodity is outside AEP's traditional economic market
area are recorded on a net basis in worldwide electric and gas
operations revenues.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's EITF 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income of
marking open trading contracts to market is deferred as regulatory
assets or liabilities for the portion of those open electricity
trading transactions within the AEP's marketing area that are
included in cost of service on a settlement basis for ratemaking
purposes in the Company's non-Virginia jurisdictions. A Virginia
jurisdiction net mark-to-market pre-tax gain of $5 million for the
year ended December 31, 1999 is included in domestic regulated
revenues as a result of an agreed prohibition against establishing
new regulatory assets in a February 1999 Virginia SCC approved
settlement agreement. Open contracts outside of AEP Power Pool's
marketing area are marked-to-market in worldwide electric and gas
operations revenues. The adoption of the EITF did not have a
material effect on results of operations, cash flows or financial
condition. All physical and financial instruments for natural gas
except for certain qualifying hedges are marked to market and are
included on a net basis in worldwide electric and gas operations
revenues. The unrealized mark-to-market gains and losses from
trading of financial instruments are reported as assets and
liabilities, respectively.
<PAGE>
The amounts of net revenues recorded in 1999 and 1998 for electric
and gas trading activities were:
Revenues - Net Gain (Loss) 1999 1998
(in millions)
Domestic Regulated Electric
Utility Operations $27 $111
Worldwide Electric and Gas Operations 14 (33)
Electric and gas trading activities were not material in 1997.
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 four years
at December 31, 1999. The Company does not presently utilize
derivatives to manage its exposures to foreign currency exchange
rate movements.
Market Valuation - The book values of cash and cash equivalents,
accounts receivable, short-term debt and accounts payable
approximate fair value because of the short-term maturity of these
instruments. The book value of the pre-April 1983 spent nuclear
fuel disposal liability approximates the Company's best estimate of
its fair value.
The book values and fair values of the Company's significant
financial instruments at December 31, 1999 and 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.
Book Value Fair Value
(in millions)
Non-Derivatives
1999
Long-term Debt $7,447 $7,209
Preferred Stock 119 117
1998
Long-term Debt 7,006 7,291
Preferred Stock 128 134
<PAGE>
Derivatives
Trading Assets
<TABLE>
<CAPTION>
1999 1998
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
GWH (in millions) GWH (in millions)
<S> <C> <C> <C> <C> <C> <C>
Electric
Futures and
Options-NYMEX (net) 224 $ 2 $ 1 - $ - $ -
Physicals 69,509 577 517 58,521 46 41
Options - OTC 6,203 39 62 3,873 32 79
Swaps 177 1 1 276 3 1
MMMBTU (in millions) MMMBTU (in millions)
Gas
Futures and
Options-NYMEX (net) - $ - $ - 55,442 $ 6 $ 2
Physicals 345,830 37 39 212,307 44 30
Options - OTC 192,593 54 40 65,920 18 12
Swaps 2,682,033 410 312 1,081,954 246 143
Trading Liabilities
GWH (in millions) GWH (in millions)
Electric
Futures and
Options-NYMEX (net) - $ - $ - 705 $ (7) $ (2)
Physicals 74,764 (536) (498) 57,652 (51) (46)
Options - OTC 8,907 (43) (56) 2,935 (29) (78)
Swaps 180 (2) (2) 490 (8) (2)
MMMBTU (in millions) MMMBTU (in millions)
Gas
Futures and
Options-
NYMEX (net) 69,840 $ (8) $ (5) - $ - $ -
Physicals 301,271 (32) (26) 180,949 (42) (29)
Options - OTC 227,225 (55) (37) 74,770 (23) (14)
Swaps 2,601,644 (379) (303) 1,092,660 (231) (136)
</TABLE>
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 position. The amount of these
deposits at December 31, 1999 and 1998 was $25 million and $10
million, respectively.
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 not experienced a significant loss due to the
credit risk; 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 assets, are
recorded at market value in accordance with SFAS 115 and consist of
tax-exempt municipal bonds and other securities. At December 31,
1999 and 1998 the fair values of the trust investments were $708
million and $648 million, respectively, and had a cost basis of
$636 million and $584 million, respectively. Accumulated gross
unrealized holding gains were $78 million and $65 million at
December 31, 1999 and 1998, respectively and accumulated gross
unrealized holding losses were $7 million and $1 million at
December 31, 1999 and 1998, respectively. The change in market
value in 1999, 1998, and 1997 was a net unrealized holding gain of
$8 million, $24 million, and $19 million, respectively.
The cost basis of trust investments by security type was:
December 31,
1999 1998
(in millions)
Tax-Exempt Bonds $351 $326
Equity Securities 116 96
Treasury Bonds 73 71
Corporate Bonds 13 11
Cash, Cash Equivalents and
Accrued Interest 83 80
Total $636 $584
Proceeds from sales and maturities of trust securities of $226
million during 1999 resulted in $6 million of realized gains and $5
million of realized losses. Proceeds from sales and maturities of
securities of $225 million during 1998 resulted in $8 million of
realized gains and $3 million of realized losses. Proceeds from
sales and maturities of trust securities of $147 million during
1997 resulted in $4 million of realized gains and $1 million of
realized losses. The cost of trust securities for determining
realized gains and losses is original acquisition cost including
amortized premiums and discounts.
<PAGE>
At December 31, 1999, the year
of maturity of trust fund investments other than equity
securities, was:
(in millions)
2000 $120
2001 - 2004 174
2005 - 2009 182
After 2009 44
Total $520
CitiPower entered into several interest rate swap agreements for
$788 million of borrowings under a 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
counter parties to an interest rate swap agreement were to default
on contractual payments, CitiPower could be exposed to increased
costs related to replacing the original agreement. However,
CitiPower does not anticipate non-performance by any counter party
to any interest rate swap in effect as of December 31, 1999. As of
December 31, 1999, CitiPower was a party to interest rate swaps
having a aggregate notional amount of $630 million, with $367
million maturing on December 31, 2000, and $263 million maturing on
December 31, 2003. The average fixed interest rate payable on the
aggregate of the interest rate swaps is 5.32%. The average
floating rate for interest rate swaps was 5.93% at December 31,
1999. The estimated fair value of the interest rate swaps, which
represents the estimated amount CitiPower would receive to
terminate the swaps at December 31, 1999, based on quoted interest
rates, is a net receivable of $17 million.
In accordance with the debt covenants included in the financing
provisions of this credit facility, CitiPower 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, 1999, CitiPower had
outstanding energy trading derivatives with a total contracted load
of 7,313 Gwh's. The maturities for these contracts range from
three months to six years. Management's estimate of the fair value
of these derivatives as of December 31, 1999 is $7 million in
excess of net contract value.
<TABLE>
<PAGE>
15. Income Taxes:
The details of income taxes as reported are as follows:
<CAPTION>
Year Ended December 31,
1999 1998 1997
(in millions)
<S> <C> <C> <C>
Federal:
Current $139 $247 $330
Deferred 116 16 (32)
Total 255 263 298
State:
Current 3 18 22
Deferred - - -
Total 3 18 22
International:
Current - - -
Deferred 2 - -
Total 2 - -
Total Income Tax as Reported $260 $281 $320
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 income taxes reported.
Year Ended December 31,
1999 1998 1997
(in millions)
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $531 $547 $ 638
Extraordinary Loss - UK Windfall Tax (Note 9) - - (109)
Federal Income Taxes 255 263 298
Pre-Tax Book Income $786 $810 $ 827
Federal Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $275 $283 $289
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 62 58 53
Corporate Owned Life Insurance 2 (16) (18)
Foreign Tax Credits (35) (8) (13)
Investment Tax Credits (net) (25) (25) (25)
Extraordinary Loss - UK Windfall Tax - - 38
State 3 18 22
International 2 - -
Other (24) (29) (26)
Total Income Taxes as Reported $260 $281 $320
Effective Income Tax Rate 32.9% 33.9% 37.7%
<PAGE>
The following tables show the elements of the Company's net
deferred tax liability and the significant temporary differences:
December 31,
1999 1998
(in millions)
Deferred Tax Assets $ 930 $ 879
Deferred Tax Liabilities (3,675) (3,480)
Net Deferred Tax Liabilities $(2,745) $(2,601)
Property Related Temporary Differences $(2,151) $(2,170)
Amounts Due From Customers For Future
Federal Income Taxes (376) (395)
Deferred State Income Taxes (205) (194)
All Other (net) (13) 158
Net Deferred Tax Liabilities $(2,745) $(2,601)
</TABLE>
The Company has settled with the IRS all issues from the audits of
its 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, COLI Litigation, in Note 6, 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.
<TABLE>
16. Supplementary Information:
<CAPTION>
Year Ended December 31,
1999 1998 1997
(in million)
<S> <C> <C> <C>
Purchased Power -
Ohio Valley Electric Corporation
(44.2% owned by AEP System) $64 $43 $30
Cash was paid for:
Interest (net of capitalized amounts) $513 $413 $390
Income Taxes $95 $282 $399
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $80 $119 $235
Assumption of Liabilities related
to Acquisitions $ - $152 $ -
</TABLE>
17. Leases:
Leases of property, plant and equipment are for periods up to 35
years and require payments of related property taxes, maintenance
and operating costs. The majority of the leases have purchase or
renewal options and will be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally
charged to operating expenses in accordance with rate-making
treatment. The components of rental costs are as follows:
Year Ended December 31,
1999 1998 1997
(in millions)
Lease Payments on Operating Leases $245 $255 $257
Amortization of Capital Leases 96 91 105
Interest on Capital Leases 34 37 31
Total Lease Rental Costs $375 $383 $393
Property, plant and equipment under capital leases and related
obligations recorded on the Consolidated Balance Sheets are as
follows:
December 31,
1999 1998
(in millions)
PROPERTY, PLANT AND EQUIPMENT UNDER CAPITAL LEASES:
Production $ 46 $ 47
Distribution 15 15
Other:
Nuclear Fuel (net of amortization) 108 104
Mining Assets and Other 612 584
Total Property, Plant and Equipment 781 750
Accumulated Amortization 261 217
Net Property, Plant and Equipment
under Capital Leases $520 $533
Obligations Under Capital Leases:
Noncurrent Liability $429 $451
Liability Due Within One Year 91 82
Total Obligations Under Capital Leases $520 $533
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1999:
Noncancelable
Capital Operating
Leases Leases
(in millions)
2000 $116 $ 234
2001 98 231
2002 74 225
2003 55 224
2004 41 223
Later Years 134 3,226
Total Future Minimum Lease Payments 518 (a) $4,363
Less Estimated Interest Element 106
Estimated Present Value of Future
Minimum Lease Payments 412
Unamortized Nuclear Fuel 108
Total $520
(a) Minimum lease payments do not include nuclear fuel payments.
The payments 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.
<PAGE>
18. Lines of Credit and Commitment Fees:
At December 31, 1999, unused short-term bank lines of credit were
available in the amount of $1,056 million. In addition one
subsidiary not engaged in providing domestic regulated electric
utility services has a line of credit under a revolving credit
agreement that expires in December 2002. The amount of credit
available under the revolving credit agreement was $20 million at
December 31, 1999. The short-term bank lines of credit and the
revolving credit agreement require the payment of facility fees and
do not require compensating balances.
Outstanding short-term debt consisted of:
December 31,
1999 1998
(dollars in millions)
Balance Outstanding:
Notes Payable $208 $198
Commercial Paper 680 419
Total $888 $617
Year-End Weighted
Average Interest Rate:
Notes Payable 6.7% 5.8%
Commercial Paper 6.5% 6.2%
Total 6.6% 6.1%
<TABLE>
19. Unaudited Quarterly Financial Information:
<CAPTION>
Quarterly Periods Ended
1999
March 31 June 30 Sept. 30 Dec. 31
(In Millions - Except
Per Share Amounts)
<S> <C> <C> <C> <C>
Operating Revenues $1,694 $1,643 $1,914 $1,665
Operating Income 381 285 376 263
Net Income 151 88 174 107
Earnings per Share* 0.79 0.46 0.90 0.55
*Amounts for 1999 do not add to $2.69 earnings per share due to rounding.
Fourth quarter 1999 earnings include various favorable adjustments
totaling $53 million. These adjustments include $21 million net of
tax from the deferral of Cook Plant restart expenses net of
amortization under the terms of a Michigan jurisdiction settlement
agreement approved on December 16, 1999 (see Note 2 for details);
$17 million net of tax from changes in estimates of state and local
taxes that resulted from the resolution of property valuation
disputes, a net operating loss carry back and adjustments to the
prior year tax accrual after filing state tax returns; $8 million
net of tax from changes in estimates for pole attachment revenues
due to adjustments to the accrual for prior billings for usage of
pole attachments by telecommunications companies; and $7 million
from a reduction in Australian income tax rates.
Quarterly Periods Ended
1998
March 31 June 30 Sept. 30 Dec. 31
(In Millions - Except
Per Share Amounts)
Operating Revenues $1,521 $1,557 $1,858 $1,461
Operating Income 344 294 413 196
Net Income 151 118 195 72
Earnings per Share 0.79 0.62 1.02 0.38
See "Reclassification" in Note 1 regarding reclassification of prior period
amounts.
</TABLE>
<TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
<CAPTION.
December 31, 1999
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding(g) Millions)
<S> <C> <C> <C> <C>
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 446,764 $ 45
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 343,100 $ 34
6.02% - 6-7/8% (c) (e) 1,950,000 597,950 60
7% (f) (f) 250,000 250,000 25
Total Subject to Mandatory
Redemption (c) $119
________________________________________________________________________________________________________
December 31, 1998
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding(g) Millions)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 460,016 $ 46
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 388,100 $ 39
6.02% - 6-7/8% (c) (e) 1,950,000 637,950 64
7% (f) (f) 250,000 250,000 25
Total Subject to Mandatory
Redemption (c) $128
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, 1999 the subsidiaries had 7,262,605, 22,200,000 and 7,611,984 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
(genera lly at par) and reacquisitions of shares in anticipation of future requirements.
The subsidiaries reac quired 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 million each year for the years 2000, 2001,
2002, $11,600,000 million in 2003 and $7,700,000 in 2004.
(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.
(g) The number of shares of preferred stock redeemed is 98,252 shares in 1999, 7,220 shares in 1998 and
4,258,947 shares in 1997.
</TABLE>
<TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
<CAPTION>
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1999 1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C> <C>
FIRST MORTGAGE BONDS
1999-2002 7.19% 6.35%-8.95% 6.35%-8.95% $ 609 $ 759
2003-2006 6.77% 6%-8% 6%-8% 783 846
2022-2025 7.92% 7.10%-8.80% 7.10%-8.80% 822 1,021
INSTALLMENT PURCHASE CONTRACTS (a)
1999-2002 5.08% 4.80%-5.55% 4.05%-5.15% 145 145
2007-2026 6.26% 5.00%-7-7/8% 5.00%-7-7/8% 806 776
NOTES PAYABLE (b)
1999-2008 6.56% 5.8675%-9.60% 5.49%-9.60% 1,594 1,493
SENIOR UNSECURED NOTES
2000-2004 6.79% 6.50%-7.45% 6-1/2%-6.73% 1,003 448
2005-2009 6.58% 6.24%-6.91% 6.24%-6.91% 488 338
2038 7.30% 7.20%-7-3/8% 7.20%-7-3/8% 340 340
JUNIOR DEBENTURES
2025 - 2038 8.05% 7.60%-8.72% 7.60%-8.72% 620 620
OTHER LONG-TERM DEBT (c) 285 269
Unamortized Discount (net) (48) (49)
Total Long-term Debt
Outstanding (d) 7,447 7,006
Less Portion Due Within One Year 1,111 206
Long-term Portion $6,336 $6,800
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 6 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease
back agreements.
(d) Long-term debt outstanding at December 31, 1999 is payable as follows:
Principal Amount (in millions)
2000 $1,111
2001 270
2002 391
2003 1,374
2004 601
Later Years 3,748
Total Principal
Amount 7,495
Unamortized
Discount (48)
Total $7,447
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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 - independent auditors
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 an evaluation of the Company's internal control structure over
financial reporting.
<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, 1999 and 1998, and the related consolidated statements of
income, comprehensive income, common shareholders' equity, and cash
flows for each of the three years in the period ended December 31, 1999.
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,
1999 and 1998, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1999 in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 22, 2000
(March 3, 2000 as to Note 7)
