Filed Pursuant to Rule 424(b)(2)
Registration No. 333-105243
PROSPECTUS SUPPLEMENT
(TO PROSPECTUS DATED APRIL 19, 2001)
AMERICAN ELECTRIC POWER LOGO
$300,000,000
AMERICAN ELECTRIC POWER COMPANY, INC.
5.25% SENIOR NOTES, SERIES D, DUE 2015
---------------------
The Senior Notes will be our unsecured and unsubordinated obligations.
Interest on the Senior Notes is payable semi-annually on June 1 and December 1
of each year, beginning December 1, 2003. The Senior Notes will mature on June
1, 2015. We may redeem the Senior Notes at our option at any time, either as a
whole or in part, in each case, at a redemption price equal to 100% of the
principal amount of the Senior Notes being redeemed plus a make-whole premium,
together with accrued and unpaid interest to the redemption date. The Senior
Notes do not have the benefit of any sinking fund. The Senior Notes are
unsecured and rank equally with all of our other unsecured and unsubordinated
indebtedness from time to time outstanding. We will issue the Senior Notes only
in registered form in multiples of $1,000.
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PER SENIOR NOTE TOTAL
--------------- ------------
Public offering price(1).................................... 99.848% $299,544,000
Underwriting discount....................................... 0.675% $ 2,025,000
Proceeds, before expenses, to us............................ 99.173% $297,519,000
---------------
(1) Plus accrued interest, if any, from May 20, 2003.
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INVESTING IN OUR SENIOR NOTES INVOLVES RISKS. SEE "RISK FACTORS" BEGINNING
ON PAGE S-7.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY
BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS IS TRUTHFUL OR COMPLETE.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
The Senior Notes will be ready for delivery in book-entry form only through
The Depository Trust Company on or about May 20, 2003.
---------------------
Joint Book-Running Managers
CREDIT SUISSE FIRST BOSTON UBS WARBURG
The date of this prospectus supplement is May 15, 2003.
YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. WE HAVE
NOT, AND THE UNDERWRITERS HAVE NOT, AUTHORIZED ANY OTHER PERSON TO PROVIDE YOU
WITH DIFFERENT INFORMATION. IF ANYONE PROVIDES YOU WITH DIFFERENT OR
INCONSISTENT INFORMATION, YOU SHOULD NOT RELY ON IT. WE ARE NOT, AND THE
UNDERWRITERS ARE NOT, MAKING AN OFFER TO SELL THESE SECURITIES IN ANY
JURISDICTION WHERE THE OFFER OR SALE IS NOT PERMITTED. YOU SHOULD ASSUME THAT
THE INFORMATION APPEARING IN THIS PROSPECTUS SUPPLEMENT, THE ACCOMPANYING
PROSPECTUS AND THE DOCUMENTS INCORPORATED BY REFERENCE IS ACCURATE ONLY AS OF
THEIR RESPECTIVE DATES. OUR BUSINESS, FINANCIAL CONDITION, RESULTS OF OPERATIONS
AND PROSPECTS MAY HAVE CHANGED SINCE THOSE DATES.
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TABLE OF CONTENTS
PAGE
----
PROSPECTUS SUPPLEMENT
Summary..................................................... S-1
Forward-Looking Statements.................................. S-6
Risk Factors................................................ S-7
Use of Proceeds............................................. S-21
Capitalization.............................................. S-22
American Electric Power Company, Inc........................ S-23
Supplemental Description of the Senior Notes................ S-28
Underwriting................................................ S-31
Notice to Canadian Residents................................ S-32
Legal Matters............................................... S-33
Experts..................................................... S-33
PROSPECTUS
The Company................................................. 1
Where You Can Find More Information......................... 1
Prospectus Supplements...................................... 2
Ratio of Earnings to Fixed Charges.......................... 2
Use of Proceeds............................................. 2
Description of the Notes.................................... 2
Plan of Distribution........................................ 6
Legal Opinions.............................................. 7
Experts..................................................... 7
This document is in two parts. The first is this prospectus supplement,
which describes the specific terms of the securities we are offering and also
adds to and updates information contained in the accompanying prospectus and the
documents incorporated by reference in that prospectus. The second part, the
accompanying prospectus, gives more general information about securities we may
offer from time to time, including securities other than those we are offering
in this prospectus supplement. If information in this prospectus supplement is
inconsistent with the accompanying prospectus, you should rely on this
prospectus supplement.
It is important for you to read and consider all of the information
contained in this prospectus supplement and the accompanying prospectus in
making your investment decision. You should also read and consider the
information in the documents we have referred you to in "Where You Can Find More
Information" on page 2 of the accompanying prospectus.
We include cross-references in this prospectus supplement and the
accompanying prospectus to captions in these materials where you can find
additional related discussions. The table of contents in this prospectus
supplement provides the pages on which these captions are located.
SUMMARY
The following information supplements, and should be read together with,
the information contained in other parts of this prospectus supplement and in
the prospectus to which it relates. This summary highlights selected information
from this prospectus supplement and the accompanying prospectus. You should also
review "Risk Factors" beginning on page S-7 of this prospectus supplement to
determine whether an investment in the Senior Notes is appropriate for you.
Unless the context requires otherwise, references to "American Electric
Power," "AEP", "we", "our" or "us" refer to American Electric Power Company,
Inc., a New York corporation, and its consolidated subsidiaries.
AMERICAN ELECTRIC POWER COMPANY, INC.
American Electric Power Company, Inc. is one of the largest investor-owned
public utility companies in the United States. We provide, directly or
indirectly, generation, transmission and distribution services to almost five
million customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana,
Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through
our utility operations.
Our portfolio of assets includes:
- 38,000 megawatts of generating capacity, the largest complement of
generation in the United States;
- 38,000 miles of transmission lines;
- 186,000 miles of distribution lines that support delivery of electricity
to our customers' premises;
- Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37
tug boats and two coal handling terminals with 20 million tons of annual
capacity);
- 6,400 miles of gas pipelines in Louisiana and Texas with 128 billion
cubic feet of gas storage facilities; and
- 4,000 megawatts of generating capacity in the U.K. and other
international investments.
BUSINESS STRATEGY
Our business is focused on utility operations in the United States, which
tend to offer more stable and relatively predictable earnings and cash flow. We
are continuing to reduce trading in markets where we do not have assets and will
focus instead on ensuring maximum value for our assets by selling output in
excess of our utility needs. This asset optimization approach has long been part
of our strategy as an active seller of excess power in the Midwest. We remain
focused on credit quality and liquidity.
Our strategy for the core business of utility operations is to:
- Maintain moderate but steady earnings growth;
- Manage the regulatory process to maximize retention of earnings and
operational improvement;
- Maximize the value of transmission assets and protect revenue stream
through regional transmission organization (RTO) membership;
- Continue process improvement to maintain distribution service quality
while enhancing financial performance; and
- Optimize generation assets through enhanced availability and sale of
excess capacity.
OVERVIEW OF UTILITY OPERATIONS
Our electric utility subsidiaries have traditionally provided electric
service, consisting of generation, transmission and distribution, on an
integrated basis to their retail customers. Our operating subsidiaries
S-1
include AEP Texas Central Company (formerly Central Power and Light Company),
AEP Texas North Company (formerly West Texas Utilities Company), Appalachian
Power Company, Columbus Southern Power Company, Indiana Michigan Power Company,
Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma,
Southwestern Electric Power Company, Kingsport Power Company, Wheeling Power
Company and AEP Generating Company. These operating subsidiaries provide,
directly or indirectly, electric service to approximately 5 million customers in
eleven states through our electric networks of over 38,000 miles of transmission
lines and 186,000 miles of distribution lines.
RESTRUCTURING
Our public utility subsidiaries, like many other electric utilities, have
traditionally provided electric generation and energy delivery, consisting of
transmission and distribution services, as a single product to their retail
customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia
that allows for customer choice of generation supplier. These measures generally
allow competition in the generation and sale of electric power, but not in
transmission and distribution. Although customer choice legislation has been
enacted in Arkansas, Oklahoma and West Virginia, such legislation has been
repealed in Arkansas, delayed indefinitely in Oklahoma and has not been
implemented in West Virginia.
Each of our Ohio utility subsidiaries currently operates as a functionally
separated electric utility company and no longer charges bundled rates for its
retail sales of electricity. Distribution rates for our Ohio utility
subsidiaries are approved by The Public Utilities Commission of Ohio and
transmission rates are approved by the Federal Energy Regulatory Commission
(FERC). We have sought regulatory approval to legally separate the transmission
and distribution assets of our Ohio utility subsidiaries from their generation
assets pursuant to Ohio restructuring legislation. However, we are presently
determining the regulatory feasibility of complying with Ohio restructuring
legislation through continued functional separation. Assuming regulatory
compliance, it is currently our intention that our Ohio utility subsidiaries
remain functionally separated. Similarly, each of our Texas utility subsidiaries
in the Electric Reliability Counsel of Texas (ERCOT) also currently operates as
a functionally separated electric utility company with distribution and, for the
most part, transmission rates that continue to be set by the Public Utility
Commission of Texas (PUCT) and with generation rates that are not set by the
PUCT. We have sought regulatory approval to legally separate the generation
assets of our Texas utility subsidiaries from their transmission and
distribution assets as required by Texas restructuring legislation.
Additionally, AEP Texas Central Company (TCC) intends to sell its generation
assets in order to accurately determine its stranded costs in accordance with
Texas restructuring legislation and PUCT regulations. Transition rules for
Michigan and Virginia do not require legal separation. Due in part to
difficulties in deregulating other markets, deregulation appears unlikely for
the foreseeable future in the other states in which we operate.
S-2
SUMMARY CONSOLIDATED FINANCIAL DATA
The following table sets forth summary consolidated financial information
for each of the periods indicated. You should read the information in this table
together with our consolidated financial statements and the other financial
information incorporated by reference in this prospectus supplement and the
accompanying prospectus.
THREE MONTHS
ENDED YEARS ENDED DECEMBER 31,
MARCH 31, ---------------------------
2003 2002 2001 2000
------------ ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE DATA)
(UNAUDITED) (AUDITED)
CONSOLIDATED STATEMENTS OF OPERATIONS DATA:
Revenues........................................... $4,080 $14,536 $13,252 $11,326
Expenses........................................... 3,480 13,273 11,070 9,552
------ ------- ------- -------
Operating Income................................... 600 1,263 2,182 1,774
Less: Investment Value and Other Impairment
Losses........................................ -- 321 -- --
Other Income (Expenses)............................ 73 124 148 18
Less: Interest, Preferred Dividend Requirements
of Subsidiaries and Minority Interest in
Finance Subsidiary............................ 217 831 867 1,010
------ ------- ------- -------
Income Before Income Taxes......................... 456 235 1,463 782
Income Taxes....................................... 200 214 546 602
------ ------- ------- -------
Income Before Discontinued Operations,
Extraordinary Items and Cumulative Effect of
Accounting Change................................ 256 21 917 180
Discontinued Operations (Loss) Income (net of
tax)............................................. (9) (190) 86 122
Income (Loss) Before Extraordinary Items and
Cumulative Effect................................ 247 (169) 1,003 302
Extraordinary Losses (net of tax):
Discontinuance of Regulatory Accounting for
Generation.................................... -- -- (48) (35)
Loss on Reacquired Debt.......................... -- -- (2) --
Cumulative Effect of Accounting Change (net of tax)
Goodwill and Other Intangible Assets............. -- (350) 18 --
Accounting for Risk Management Contracts......... (49) -- -- --
Asset Retirement Obligation...................... 242 -- -- --
------ ------- ------- -------
Net Income (Loss).................................. $ 440 $ (519) $ 971 $ 267
====== ======= ======= =======
Average Number of Shares Outstanding............... 356 332 322 322
====== ======= ======= =======
Earnings Per Share:
Income Before Discontinued Operations,
Extraordinary Items and Cumulative Effect of
Accounting Changes............................ $ 0.72 $ 0.06 $ 2.85 $ 0.56
Discontinued Operations (Loss)................... (0.02) (0.57) 0.26 0.38
Extraordinary Losses............................. -- -- (0.16) (0.11)
Cumulative Effect of Accounting Changes.......... 0.54 (1.06) 0.06 --
------ ------- ------- -------
Earnings (Loss) Per Share (Basic and Diluted).... $ 1.24 $ (1.57) $ 3.01 $ 0.83
====== ======= ======= =======
Cash Dividends Paid Per Share...................... $ 0.60 $ 2.40 $ 2.40 $ 2.40
====== ======= ======= =======
S-3
MARCH 31, DECEMBER 31, DECEMBER 31,
2003 2002 2001
--------- ------------ ------------
(UNAUDITED) (AUDITED)
CONSOLIDATED BALANCE SHEET DATA:
Total Current Assets.......................... $ 7,444 $ 6,101 $ 5,664
Net Property, Plant and Equipment............. 22,328 21,684 22,104
Regulatory Assets............................. 2,669 2,688 3,162
Investments and Other Assets.................. 4,180 4,021 3,692
Assets Held for Sale.......................... 280 247 721
Assets of Discontinued Operations............. -- -- 3,954
------- ------- -------
Total Assets.................................. $36,901 $34,741 $39,297
======= ======= =======
MARCH 31, DECEMBER 31, DECEMBER 31,
2003 2002 2001
--------- ------------ ------------
CAPITALIZATION:
Total Debt(1)................................. $12,747 $13,660 $13,516
Certain Subsidiary Obligated, Mandatorily
Redeemable, Preferred Securities of
Subsidiary Trusts Holding Solely Junior
Subordinated Debentures of Such
Subsidiaries................................ 321 321 321
Minority Interest in Finance Subsidiary....... 759 759 750
Cumulative Preferred Stock of Subsidiaries.... 144 145 156
Total Common Shareholders' Equity............. 8,437 7,064 8,229
------- ------- -------
Total Capitalization........................ $22,408 $21,949 $22,972
======= ======= =======
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(1) Includes Short-term Debt, Equity Units and Long-term Debt due within one
year.
S-4
THE OFFERING
Senior Notes.................. $300,000,000 principal amount of 5.25% Senior
Notes, Series D, due 2015.
Maturity Date................. The Senior Notes will mature on June 1, 2015.
Interest Rate................. The Senior Notes will bear interest at the rate
of 5.25% per year.
Interest Payment Dates........ Interest on the Senior Notes is payable
semi-annually on June 1 and December 1 of each
year, beginning December 1, 2003.
Redemption.................... We may redeem the Senior Notes at our option at
any time, either as a whole or in part, in each
case, at a redemption price equal to 100% of
the principal amount of the Senior Notes being
redeemed plus a make-whole premium, together
with accrued and unpaid interest to the
redemption date.
Ranking....................... The Senior Notes will be unsecured and
unsubordinated obligations ranking equally with
our other outstanding and future unsecured and
unsubordinated indebtedness.
Restrictive Covenants......... For a discussion of the restrictive covenants
relating to the Senior Notes, see "Limitation
on Liens on Stock of Certain Subsidiaries" and
"Limitation upon Mergers, Consolidations and
Sale of Assets" under "Supplemental Description
of the Senior Notes -- Restrictive Covenants
Relating to the Senior Notes" in this
prospectus supplement.
S-5
FORWARD-LOOKING STATEMENTS
Some statements contained or incorporated by reference in this prospectus
supplement, including the discussion of our plans and proposals under
"Summary -- American Electric Power Company, Inc." and "American Electric Power
Company, Inc." are forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. These forward-looking statements are
subject to various risks and uncertainties. Actual results may vary materially.
Factors that could cause actual results to differ materially include, but are
not limited to:
- electric load and customer growth;
- abnormal weather conditions;
- available sources and costs of fuel;
- availability of generating capacity;
- the speed and degree to which competition is introduced in our service
territories;
- the ability to recover stranded costs in connection with
possible/proposed deregulation;
- new legislation and government regulation;
- oversight and/or investigation of the energy sector or its participants;
- our ability to successfully control our costs;
- the success of new business ventures and disposing of existing
investments that no longer match our corporate profile;
- international and country-specific developments affecting our foreign
investments, including the dispositions of any current foreign
investments and potential additional foreign investments;
- the economic climate and growth in our service territory and changes in
market demand and demographic patterns;
- inflationary trends;
- electricity and gas market prices;
- interest rates;
- liquidity in the banking, capital and wholesale power markets;
- actions of rating agencies;
- changes in technology, including the increased use of distributed
generation within our transmission and distribution service territory;
and
- other risks and unforeseen events, including wars, the effects of
terrorism, embargoes and other catastrophic events.
In light of these risks, uncertainties and assumptions, the forward-looking
statements contained or incorporated by reference in this prospectus supplement
might not occur. Neither AEP nor the underwriters undertake any obligation to
publicly update or revise any forward-looking statements, whether as a result of
new information, future events or otherwise.
S-6
RISK FACTORS
You should carefully consider the risks described below as well as other
information contained or incorporated by reference in this prospectus supplement
and the accompanying prospectus before buying the Senior Notes. These are risks
we consider to be material to your decision whether to invest in the Senior
Notes at this time. There may be risks that you view in a different way than we
do, and we may omit a risk that we consider immaterial, but you consider
important. If any of the following risks occur, our business, financial
condition or results of operations could be materially harmed. In that case, the
value or trading price of the Senior Notes could decline, and you may lose all
or part of your investment.
RISKS RELATED TO OUR ENERGY TRADING AND WHOLESALE BUSINESSES
WE HAVE SIGNIFICANTLY REDUCED THE SCOPE AND SCALE OF OUR ENERGY TRADING AND
MARKETING OPERATIONS.
In October 2002, AEP announced its plans to reduce the exposure to energy
trading markets of its subsidiaries that trade energy and to downsize the
trading and wholesale marketing operations conducted on behalf of such
subsidiaries. It is expected that in the future our energy trading and marketing
operations will be limited to risk management around our generation assets.
Trading and marketing operations that were not limited to risk management around
such assets have contributed to our wholesale revenues and earnings in the past.
Management is unable to predict the effect this downsizing of our trading
operations will have on our future results of operations and cash flows. The
following risk factors appearing under this subheading should be read in light
of the announcements discussed in this paragraph.
OUR REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO MARKET RISKS THAT ARE
BEYOND OUR CONTROL.
We sell power from our generation facilities into the spot market or other
competitive power markets or on a contractual basis. We also enter into
contracts to purchase and sell electricity, natural gas and coal as part of our
power marketing and energy trading operations. With respect to such
transactions, we are not guaranteed any rate of return on our capital
investments through mandated rates, and our revenues and results of operations
are likely to depend, in large part, upon prevailing market prices for power in
our regional markets and other competitive markets. These market prices may
fluctuate substantially over relatively short periods of time. It is reasonable
to expect that trading margins may erode as markets mature and that there may be
diminished opportunities for gain should volatility decline. In addition, the
FERC, which has jurisdiction over wholesale power rates, as well as independent
system operators that oversee some of these markets, may impose price
limitations, bidding rules and other mechanisms to address some of the
volatility in these markets. Fuel prices may also be volatile, and the price we
can obtain for power sales may not change at the same rate as changes in fuel
costs. These factors could reduce our margins and therefore diminish our
revenues and results of operations.
Volatility in market prices for fuel and power may result from:
- weather conditions;
- seasonality;
- power usage;
- illiquid markets;
- transmission or transportation constraints or inefficiencies;
- availability of competitively priced alternative energy sources;
- demand for energy commodities;
- natural gas, crude oil and refined products, and coal production levels;
- natural disasters, wars, embargoes and other catastrophic events; and
- federal, state and foreign energy and environmental regulation and
legislation.
S-7
WE ARE UNABLE TO PREDICT THE COURSE, RESULTS OR IMPACT, IF ANY, OF CURRENT OR
FUTURE ENERGY MARKET INVESTIGATIONS.
In February 2002, the FERC issued an order directing its staff to conduct a
fact-finding investigation into whether any entity, including Enron Corp.,
manipulated short-term prices in electric energy or natural gas markets in the
West or otherwise exercised undue influence over wholesale prices in the West,
for the period January 1, 2000, forward. In April 2002, we furnished certain
information to the FERC in response to their related data request.
Pursuant to the FERC's February order, on May 8, 2002, the FERC issued
further data requests, including requests for admissions, with respect to
certain trading strategies engaged in by Enron and, allegedly, traders of other
companies active in the wholesale electricity and ancillary services markets in
the West, particularly California, during the years 2000 and 2001. This data
request was issued to us as part of a group of over 100 entities designated by
the FERC as all sellers of wholesale electricity and/or ancillary services to
the California Independent System Operator and/or the California Power Exchange.
The May 8, 2002 FERC data request required senior management to conduct an
investigation into our trading activities during 2000 and 2001 and to provide an
affidavit as to whether we engaged in certain trading practices that the FERC
characterized in the data request as being potentially manipulative. Senior
management complied with the order and denied our involvement with those trading
practices.
On May 21, 2002, the FERC issued a further data request with respect to
this matter to us and over 100 other market participants requesting information
for the years 2000 and 2001 concerning "wash," "round trip" or "sale/buy back"
trading in the Western System Coordinating Council (WSCC), which involves the
sale of an electricity product to another company together with a simultaneous
purchase of the same product at the same price (collectively, "wash sales").
Similarly, on May 22, 2002, the FERC issued an additional data request with
respect to this matter to us and other market participants requesting similar
information for the same period with respect to the sale of natural gas products
in the WSCC and Texas. After reviewing our records, we responded to the FERC
that we did not participate in any "wash sale" transactions involving power or
gas in the relevant market. We further informed the FERC that certain of our
traders did engage in trades on the Intercontinental Exchange, an electronic
electricity trading platform owned by a group of electricity trading companies,
including us, on September 21, 2001, the day on which all brokerage commissions
for trades on that exchange were donated to charities for the victims of the
September 11, 2001 terrorist attacks, which do not meet the FERC criteria for a
"wash sale" but do have certain characteristics in common with such sales. In
response to a request from the California attorney general for a copy of AEP's
responses to the FERC inquiries, we provided the pertinent information.
The Public Utilities Commission of Texas also issued similar data requests
to us and other power marketers. We responded to such data request by the July
2, 2002 response date. The US Commodity Futures Trading Commission (CFTC) issued
a subpoena to us on June 17, 2002 requesting information with respect to "wash
sale" trading practices. We responded to CFTC. In addition, the US Department of
Justice made a civil investigation demand to us and other electric generating
companies concerning their investigation of the Intercontinental Exchange. We
have completed a review of our trading activities in the United States for the
last three years involving sequential trades with the same terms and
counterparties. The revenue from such trading is not material to our financial
statements. We believe that substantially all these transactions involve
economic substance and risk transference and do not constitute "wash sales".
In August 2002, we received an informal data request from the SEC asking us
to voluntarily provide documents related to "round trip" or "wash" trades. We
have provided the requested information to the SEC. In March 2003, we received a
subpoena from the SEC. The subpoena seeks additional information and is part of
the SEC's formal investigative process.
In September 2002, we received a subpoena from the FERC requesting
information about our natural gas transactions and their potential impact on gas
commodity prices in the New York City area. We responded to the subpoena in
October 2002.
S-8
In October 2002, we dismissed several employees involved in natural gas
marketing and trading after the company determined that they provided inaccurate
price information for use in indexes compiled and published by trade
publications. Subsequently, we instituted measures that require all price
information for use in market indexes be verified and reported through the
organization of our Chief Risk Officer. We have and will continue to provide to
the FERC, the SEC and the CFTC information relating to price data given to
energy industry publications.
Management is unable to predict the course or outcome of these or any
future energy market investigations or their impact, if any, on power commodity
trading generally or, more specifically, on our trading operations or future
results of operations and cash flows.
OUR ENERGY TRADING (INCLUDING FUEL PROCUREMENT AND POWER MARKETING) AND RISK
MANAGEMENT POLICIES CANNOT ELIMINATE THE RISK ASSOCIATED WITH THESE
ACTIVITIES.
Our energy trading (including fuel procurement and power marketing)
activities expose us to risks of commodity price movements. We attempt to manage
our exposure through enforcement of established risk limits and risk management
procedures. These risk limits and risk management procedures may not always be
followed or may not work as planned and cannot eliminate the risks associated
with these activities. As a result, we cannot predict the impact that our energy
trading and risk management decisions may have on our business, operating
results or financial position.
We routinely have open trading positions in the market, within established
guidelines, resulting from the management of our trading portfolio. To the
extent open trading positions exist, fluctuating commodity prices can improve or
diminish our financial results and financial position.
Our energy trading and risk management activities, including our power
sales agreements with counterparties, rely on projections that depend heavily on
judgments and assumptions by management of factors such as the future market
prices and demand for power and other energy-related commodities. These factors
become more difficult to predict and the calculations become less reliable the
further into the future these estimates are made. Even when our policies and
procedures are followed and decisions are made based on these estimates, results
of operations may be diminished if the judgments and assumptions underlying
those calculations prove to be wrong or inaccurate. Our policies and procedures
do not typically require us to hedge the new trading positions that we enter
into daily.
OUR FINANCIAL PERFORMANCE MAY BE ADVERSELY AFFECTED IF WE ARE UNABLE TO
SUCCESSFULLY OPERATE OUR ELECTRIC GENERATING FACILITIES.
Our performance depends on the successful operation of our electric
generating facilities. Operating electric generating facilities involves many
risks, including:
- operator error and breakdown or failure of equipment or processes;
- operating limitations that may be imposed by environmental or other
regulatory requirements;
- labor disputes;
- fuel supply interruptions; and
- catastrophic events such as fires, earthquakes, explosions, floods or
other similar occurrences.
A decrease or elimination of revenues from power produced by our electric
generating facilities or an increase in the cost of operating the facilities
would adversely affect our results of operations.
PARTIES WITH WHOM WE HAVE CONTRACTS MAY FAIL TO PERFORM THEIR OBLIGATIONS,
WHICH COULD HARM OUR RESULTS OF OPERATIONS.
We are exposed to the risk that counterparties that owe us money or energy
will breach their obligations. Should the counterparties to these arrangements
fail to perform, we may be forced to enter into alternative hedging arrangements
or honor underlying commitments at then-current market prices that may exceed
our
S-9
contractual prices, which would cause our financial results to be diminished and
we might incur losses. Although our estimates take into account the expected
probability of default by a counterparty, our actual exposure to a default by a
counterparty may be greater than the estimates predict if defaults by
counterparties exceed our estimates.
WE RELY ON ELECTRIC TRANSMISSION FACILITIES THAT WE DO NOT OWN OR CONTROL. IF
THESE FACILITIES DO NOT PROVIDE US WITH ADEQUATE TRANSMISSION CAPACITY, WE MAY
NOT BE ABLE TO DELIVER OUR WHOLESALE ELECTRIC POWER TO OUR CUSTOMERS.
We depend on transmission facilities owned and operated by other power
companies to deliver the power we sell at wholesale. This dependence exposes us
to a variety of risks. If transmission is disrupted, or transmission capacity is
inadequate, we may not be able to sell and deliver our wholesale products. If a
region's power transmission infrastructure is inadequate, our recovery of
wholesale costs and profits may be limited. If restrictive transmission price
regulation is imposed, the transmission companies may not have sufficient
incentive to invest in expansion of transmission infrastructure.
The FERC has issued electric and gas transmission initiatives that require
electric and gas transmission services to be offered unbundled from commodity
sales. Although these initiatives are designed to encourage wholesale market
transactions for electricity and gas, access to transmission systems may in fact
not be available if transmission capacity is insufficient because of physical
constraints or because it is contractually unavailable. We also cannot predict
whether transmission facilities will be expanded in specific markets to
accommodate competitive access to those markets.
WE DO NOT FULLY HEDGE AGAINST PRICE CHANGES IN COMMODITIES.
We routinely enter into contracts to purchase and sell electricity, natural
gas and coal as part of our power marketing and energy trading operations and to
procure fuel. In connection with these trading activities, we routinely enter
into financial contracts, including futures and options, over-the counter
options, swaps and other derivative contracts. These activities expose us to
risks from price movements. If the values of the financial contracts change in a
manner we do not anticipate, it could harm our financial position or reduce the
financial contribution of our trading operations.
We manage our exposure by establishing risk limits (which we have recently
lowered as part of our announced effort to reduce the degree and scale of our
trading and marketing operations) and entering into contracts to offset some of
our positions (i.e., to hedge our exposure to demand, market effects of weather
and other changes in commodity prices). However, we do not always hedge the
entire exposure of our operations from commodity price volatility. To the extent
we do not hedge against commodity price volatility, our results of operations
and financial position may be improved or diminished based upon our success in
the market.
WE ARE EXPOSED TO LOSSES RESULTING FROM THE BANKRUPTCY OF ENRON CORP.
On October 15, 2002, certain of our subsidiaries filed claims against Enron
Corp. and its subsidiaries in the bankruptcy proceeding filed by the Enron
entities which are pending in the U.S. Bankruptcy Court for the Southern
District of New York. At the date of Enron's bankruptcy we had open trading
contracts and trading accounts receivables and payables with Enron. In addition,
on June 1, 2001, we purchased Houston Pipe Line Company (HPL) from Enron.
Various HPL related contingencies and indemnities remained unsettled at the date
of Enron's bankruptcy. The timing of the resolution of the claims by the
Bankruptcy Court is not certain.
In connection with the 2001 acquisition of HPL, we acquired exclusive
rights to use and operate the underground Bammel gas storage facility pursuant
to an agreement with BAM Lease Company, a now-bankrupt subsidiary of Enron. This
right is for a term of 30 years, with a renewal right for another 20 years and
includes the use of the Bammel storage reservoir and the related compression,
treating and delivery systems. We have engaged in preliminary discussions with
Enron concerning the possible purchase of the residual interest held by Enron in
the Bammel storage facility and the possible resolution of outstanding issues
between AEP and Enron relating to our acquisition of its interest in the Bammel
storage facility. We are unable to predict whether these discussions will lead
to an agreement on these subjects. If these discussions do not lead
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to an agreement, there may be a dispute with Enron concerning our ability to
continue utilization of the Bammel storage facility under the existing
agreement.
We also entered into an agreement with BAM Lease Company which grants HPL
the right to use approximately 65 billion cubic feet of cushion gas (or pad gas)
required for the normal operation of the Bammel gas storage facility. The Bammel
Gas Trust, which purportedly owned approximately 55 billion cubic feet of the
gas, had entered into a financing arrangement in 1997 with Enron and a group of
banks. These banks purported to have certain rights to the gas in certain events
of default. In connection with our acquisition of HPL, the banks entered into an
agreement granting HPL's use of the cushion gas and released HPL from
liabilities and obligations under the financing arrangement. HPL was thereafter
informed by the banks of a purported default by Enron under the terms of the
referenced financing arrangement. In July 2002 the banks filed a lawsuit against
HPL seeking a declaratory judgment that they have a valid and enforceable
security interest in this cushion gas which would permit them to cause the
withdrawal of this gas from the storage facility. In September 2002 HPL filed a
general denial and certain counterclaims against the banks. Management is unable
to predict the outcome of this lawsuit or its impact on results of operations
and cash flows.
In 2001 we expensed $47 million ($31 million net of tax) for our estimated
loss from the Enron bankruptcy. In 2002 we expensed an additional $6 million for
a cumulative loss of $53 million ($34 million net of tax). The amounts expensed
were based on an analysis of contracts where AEP subsidiaries and Enron entities
are counterparties, the offsetting of receivables and payables, the application
of deposits from Enron entities and management's analysis of the HPL related
purchase contingencies and indemnifications.
Enron has recently instituted proceedings against other energy trading
counter-parties challenging the practice of utilizing offsetting receivables and
payables and related collateral across various Enron entities. We believe that
we have the right to utilize similar procedures in dealing with payables,
receivables and collateral with Enron entities by offsetting approximately $110
million of trading payables owed to various Enron entities against trading
receivables due to us. We believe we have legal defenses to any challenge that
may be made to the utilization of such offsets but at this time are unable to
predict the ultimate resolution of this issue.
WE ARE EXPOSED TO THE RISK OF FURTHER IMPAIRMENT AND LOSSES RESULTING FROM OUR
INVESTMENT IN GENERATION ASSETS IN THE UNITED KINGDOM.
In December 2001, we acquired two coal-fired generation plants in the
United Kingdom for a cash payment of $942.3 million and assumption of certain
liabilities. Subsequent to our acquisition, wholesale electric power prices
declined sharply in that market as a result of over-capacity and static demand.
External industry forecasts and our own projections made during the fourth
quarter of 2002 indicate that this situation may extend many years into the
future. As a result, the fixed asset carrying value at year-end 2002 for this
investment was substantially impaired. A December 2002 probability-weighted
discounted cash flow analysis of the fair value of our investment indicated a
2002 pre-tax impairment loss of $548.7 million. At the time this impairment was
announced we stated that we would be evaluating if the plants would continue to
operate. If we decide to cease operations at these plants or if external market
conditions further deteriorate, we could sustain additional impairment to the
value of these assets. If we do not cease operations and over-capacity and
static demand continue or worsen in that market, we expect to sustain additional
losses associated with these plants. Management is unable to predict whether
these plants will continue operations or the impact on our future results of
operations, cash flows and financial condition resulting from this investment.
DIMINISHED LIQUIDITY IN THE WHOLESALE POWER MARKETS COULD NEGATIVELY IMPACT
OUR EARNINGS.
The Enron Corp. bankruptcy and enhanced regulatory scrutiny have
contributed to more rigorous credit rating review of wholesale power market
participants. Credit downgrades and financial difficulties of certain other
market participants have significantly reduced such participants' participation
in the wholesale power markets. These events are causing a decrease in the
number of significant participants in the wholesale power markets, at least
temporarily, which could result in a decrease in the volume and liquidity in the
wholesale power markets. Such decreases have had a negative impact on our
results of operations, cash flows and
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financial condition. Reduced liquidity in these markets could also hamper our
efforts to exit transactions not related to risk management of our assets that
we entered into before reducing the scale of our power trading and marketing
operations. We are unable to predict the extent of the impact on our power
marketing and trading business if such developments continue.
POTENTIAL FOR DISRUPTION IF THE DELAY OF A FERC MARKET POWER MITIGATION ORDER
IS LIFTED.
A FERC order on our triennial market based wholesale power rate
authorization update required certain mitigation actions that certain of our
subsidiaries would need to take for sales/purchases within their respective
control areas and required us to post information on our website regarding our
power systems status. As a result of a request for rehearing filed by us and
other market participants, FERC issued an order delaying the effective date of
the mitigation plan until after a planned technical conference on market power
determination. No such conference has been held and management is unable to
predict the timing of any further action by the FERC or its affect on future
results of our operations and cash flows.
RISKS RELATED TO OUR REGULATED BUSINESS AND EVOLVING REGULATION
WE OPERATE IN A NON-UNIFORM AND FLUID REGULATORY ENVIRONMENT.
AEP is subject to regulation by the SEC under the Public Utility Holding
Company Act of 1935 (PUHCA). The rates charged by the domestic utility
subsidiaries are approved by the FERC and the eleven state utility commissions.
The FERC regulates wholesale electricity operations and transmission rates and
the state commissions regulate retail generation and distribution rates. The
prices charged by foreign subsidiaries located in China, Mexico and Brazil are
regulated by the authorities of those respective countries and are generally
subject to price controls. Six of the eleven state retail jurisdictions in which
our domestic electric utilities operate have enacted restructuring legislation.
Restructuring legislation in Texas requires the legal separation of generation
and related assets from the transmission and distribution assets of the electric
utilities in that state. In Ohio, we are determining the regulatory feasibility
of complying with restructuring legislation through the continued functional
separation of the operations of our Ohio utility subsidiaries. As a result of
restructuring legislation in Texas and Ohio, approximately one half of our
domestic generation is no longer directly regulated by state utility commissions
as to rates. The remaining four states of the six that have enacted
restructuring legislation contemplated, at least initially, some level of
regulatory reform. Our utility operations in the five state retail jurisdictions
that have not enacted any restructuring legislation currently plan to adhere to
the vertically-integrated utility model with cost recovery through regulated
rates.
Our business plan is based on the regulatory framework as described and
assumes that deregulated generation will not be re-regulated. There can be no
assurance that the states that have pursued restructuring will not reverse such
policies; nor can there be assurance that the states that have not enacted
restructuring legislation will not do so in the future. In addition to the
multiple levels of regulation at the state level in which we operate, our
business is subject to extensive federal regulation. There can be no assurance
that the federal legislative and regulatory initiatives (which have occurred
over the past few years and which have generally facilitated competition in the
energy sector) will continue or will not be reversed.
Further alteration of the regulatory landscape in which we operate will
impact the effectiveness of our business plan and may, because of the continued
uncertainty, harm our financial condition and results of operations.
RISKS RELATING TO STATE RESTRUCTURING
WE HAVE LIMITED ABILITY TO PASS ON TO OUR CUSTOMERS OUR COSTS OF PRODUCTION.
We are exposed to risk from changes in the market prices of coal and
natural gas used to generate power where generation is no longer regulated or
where existing fuel clauses are suspended or frozen. The protection afforded by
retail fuel clause recovery mechanisms has been eliminated by the implementation
of customer choice in Ohio (effective January 1, 2001) and, to a lesser degree,
in the ERCOT area of Texas (effective January 1, 2002). We expect that there may
be similar risks should customer choice be similarly implemented
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in other states. Because the risk of fuel price increases, increased
environmental compliance costs and generating unit outage cannot be passed
through to customers during the transition period in Ohio and only partially in
Texas upon regulatory approval, we retain these risks.
The protection afforded by fuel clause recovery mechanisms has been capped
or frozen by settlement agreements currently in place in Indiana (through 2004)
and Michigan (through 2003). To the extent all of the fuel supply of the
generating units in these states are not under fixed price long-term contracts
we are subject to market price risk. We continue to be protected against market
price changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky,
Virginia (through the transition to competition on July 1, 2007) and the
Southwest Power Pool (SPP) area of Texas (until the implementation of
restructuring). A fuel clause in West Virginia has been suspended per a
settlement reached in a state restructuring proceeding. However, as
restructuring has not been implemented in West Virginia, the fuel clause may be
reactivated.
Until the transition to full market competition is complete in Ohio on
December 31, 2005, our Ohio regulated utility subsidiaries there are required to
provide power at capped rates, which may be below current market rates, to
retail customers that do not choose an alternative power generation supplier.
Following the transition, it is unclear whether our retail sales of power in
Ohio will be at a market rate or at a rate determined by some level of state
utility commission involvement. Further action by the state utility commission
may be necessary to resolve this uncertainty.
OUR DEFAULT SERVICE OBLIGATIONS IN OHIO DO NOT RESTRICT CUSTOMERS FROM
SWITCHING SUPPLIERS OF POWER.
Those default service customers that we serve in Ohio may choose to
purchase power from alternative suppliers. Should they choose to switch from us,
our sales of power may decrease. Customers originally choosing alternative
suppliers may switch to our default service obligations. This may increase
demand above our facilities' available capacity. Thus, any such switching by
customers could have an adverse effect on our results of operations and
financial position. Conversely, to the extent the power sold to meet the default
service obligations could have been sold to third parties at more favorable
wholesale prices, we will have incurred potentially significant lost opportunity
costs.
SOME LAWS AND REGULATIONS GOVERNING RESTRUCTURING OF THE WHOLESALE GENERATION
MARKET IN MICHIGAN, OKLAHOMA, VIRGINIA AND WEST VIRGINIA HAVE NOT YET BEEN
INTERPRETED OR ADOPTED AND COULD HARM OUR BUSINESS, OPERATING RESULTS AND
FINANCIAL CONDITION.
While the electric restructuring laws in Michigan, Oklahoma, Virginia and
West Virginia established the general framework governing the retail electric
market, the laws required the utility commission in each state to issue rules
and determinations implementing the laws. Some of the regulations governing the
retail electric market have not yet been adopted by the utility commission in
each state. These laws, when they are interpreted and when the regulations are
developed and adopted, may harm our business, results of operations and
financial condition. Virginia restructuring legislation was enacted in 1999
providing for retail choice of generation suppliers to be phased in over two
years beginning January 1, 2002. It required jurisdictional utilities to
unbundle their power supply and energy delivery rates and to file functional
separation plans by January 1, 2002. Our Virginia subsidiary filed its plan and,
following Virginia state utility commission approval of a settlement agreement,
now operates in Virginia as a functionally separated electric utility charging
unbundled rates for its retail sales of electricity. The settlement agreement
addressed functional separation, leaving decisions related to legal separation
for later VSCC consideration.
In June 2001, Oklahoma enacted legislation delaying competition
indefinitely. The West Virginia legislature approved electricity restructuring;
however, the West Virginia Public Service Commission (WVPSC) cannot implement
the restructuring plan until the legislature makes tax law changes necessary to
preserve the revenues of state and local governments. Since the legislature has
not passed the required tax law changes, the restructuring plan has not become
effective. We cannot predict the impact of such a development.
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THERE IS UNCERTAINTY AS TO OUR RECOVERY OF DEFERRED FUEL BALANCES AND STRANDED
COSTS RESULTING FROM INDUSTRY RESTRUCTURING IN TEXAS.
The PUCT review and reconciliation of retail fuel clause recovery was
eliminated in the ERCOT area of Texas effective January 1, 2002. In 2002 we
filed final fuel reconciliation plans with the PUCT to reconcile the fuel costs
of our Texas utility subsidiaries for the relevant periods. The ultimate
recovery of deferred fuel balances at December 31, 2001 will be decided as part
of PUCT-required true-up proceedings in 2004 (the 2004 true-up proceeding). If
the final under-recovered fuel balances or any amounts incurred but not yet
reconciled are disallowed, it would harm our financial condition and diminish
our results of operations. We have reported in a fuel reconciliation that we
filed with the PUCT an over-recovery of fuel and related costs of $36.0 million
out of a total $1.9 billion in fuel expenses collected by us. The PUCT has yet
to act on our filing.
As a part of restructuring in Texas, electric utilities are allowed to
recover stranded generation costs including generation-related regulatory
assets. TCC included regulatory assets not approved for securitization in its
request for recovery of $1.1 billion of stranded costs. In a 1997 TCC PUCT rate
proceeding, $800 million of nuclear unit costs included in property, plant and
equipment-electric and regulatory assets on the consolidated balance sheets was
determined to be excess cost over market (ECOM). The PUCT provided for a lower
return on ECOM assets and ECOM assets are being amortized on an accelerated
basis for rate-making purposes. After hearings on the issue of stranded costs in
a proceeding to establish restructured rates for TCC, the PUCT ruled in October
2001 that its current estimate of our stranded costs was negative $615 million.
We have appealed the PUCT's ruling.
The final amount of stranded costs will be established by the PUCT in the
2004 true-up proceeding. For the purpose of determining stranded costs, we
intend to sell the generation assets of TCC. In order to use the sale of assets
valuation method, that subsidiary must sell all of its generating assets
including its interest in the STP nuclear generating facility. If we do not sell
the generation assets, we intend to pursue the use of a combination of other
market valuation methods. We have requested that the 2004 true-up proceeding be
scheduled after the divestiture of the generation assets is completed, currently
anticipated to be mid-year 2004. The amount of stranded costs under this
methodology will be the amount by which the net book value of TCC's generating
assets including regulatory assets and liabilities that were not securitized
exceed the market value of the generation assets as measured by the net proceeds
from the sale of assets.
If our total stranded costs determined in the 2004 true-up proceeding are
less than the amount of securitized regulatory assets, the PUCT can implement an
offsetting credit to transmission and distribution rates charged for
transmission and distribution service. The Texas Third Court of Appeals ruled in
February 2003 that any negative stranded costs in excess of securitized
regulatory assets cannot be refunded to customers under Senate Bill 7, the Texas
electricity restructuring legislation. In addition, the Court ruled that
negative stranded costs cannot be offset against other true-up adjustments
including final under-recovered fuel amounts. An offsetting credit, if imposed,
would limit our recovery of regulatory assets and may harm our results of
operations and financial condition.
Management believes that TCC will have stranded costs in 2004, and that the
current treatment of excess earnings will be amended at that time. In addition
to our appeal of the PUCT's estimate of stranded costs and refund of excess
earnings, unaffiliated parties also appealed the PUCT's refund order contending
the entire $615 million of negative stranded costs should be refunded presently.
Management is unable to predict the outcome of this litigation. An unfavorable
ruling would harm our results of operations, cash flows and possibly financial
condition.
THE NRC AND/OR THE SEC MAY NOT APPROVE THE CORPORATE SEPARATION PLANS WE HAVE
SUBMITTED TO COMPLY WITH RESTRUCTURING LEGISLATION IN TEXAS.
We have filed requests with the FERC, PUCT and SEC to legally separate and
transfer the generation assets of our Texas utility subsidiaries to new
subsidiaries formed to hold such assets. The PUCT and the FERC have approved
such plans (and, at the FERC, other action unrelated to compliance with Texas
restructuring legislation). We intend to sell the generation assets of TCC in
order to accurately determine its stranded costs in accordance with Texas
restructuring legislation and PUCT regulations. In order to use the
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sale of assets valuation method, that subsidiary must sell all of its generating
assets including its interest in STP. If we do not sell the generation assets,
we intend to pursue the use of a combination of other market valuation methods.
Divestiture of our interest in the STP to a nonaffiliate will require NRC
approval. The transfer of generation assets from our Texas subsidiaries, whether
to affiliated or unaffiliated entities, will require approval by the SEC. We can
give no assurance, however, that the NRC and/or the SEC will approve the action
necessary to complete the corporate separations. Failure to approve may limit
our ability to efficiently operate our business.
In addition, while not a condition to implementation of legal separation,
we are seeking to exempt our deregulated generation assets in Texas from
regulation as utilities under PUHCA. To obtain this exemption, each of the
eleven state utility commissions in which we operate must make certain findings
regarding the impact of the exemption in their respective states. The SEC and
the FERC must also act before the exemption is granted. We believe we will
obtain all necessary approvals for the exemption; we can give no assurance,
however, that the states, the FERC, the SEC and/or the relevant state utility
commissions will approve the action necessary. Failure to do so may limit our
ability to maximize the return on our deregulated generation assets.
COLLECTION OF OUR REVENUES IN TEXAS IS CONCENTRATED IN A LIMITED NUMBER OF
RETAIL ELECTRIC PROVIDERS (REPS).
Our revenues from the distribution of electricity in Texas are collected
from REPs that supply the electricity we distribute to their customers.
Currently, we do business with approximately thirty REPs. Adverse economic
conditions, structural problems in the new Texas market or financial
difficulties of one or more REPs could impair the ability of these REPs to pay
for our services or could cause them to delay such payments. We depend on these
REPs for timely remittance of payments. Any delay or default in payment could
adversely affect the timing and receipt of our cash flows thereby have an
adverse effect on our liquidity. We anticipate that more than half of our
revenues from REPs will come from our formerly affiliated REPs that were sold to
an affiliate of Centrica plc in December 2002.
WE MAY NOT BE ABLE TO RESPOND EFFECTIVELY TO COMPETITION.
We may not be able to respond in a timely or effective manner to the many
changes in the power industry that may occur as a result of regulatory
initiatives to increase competition. These regulatory initiatives may include
deregulation of the electric utility industry in some markets and privatization
of the electric utility industry in others. To the extent that competition
increases, our profit margins may be negatively affected. Industry deregulation
and privatization may not only continue to facilitate the current trend toward
consolidation in the utility industry but may also encourage the disaggregation
of other vertically integrated utilities into separate generation, transmission
and distribution businesses. As a result, additional competitors in our industry
may be created, and we may not be able to maintain our revenues and earnings
levels or pursue our growth strategy.
While demand for power is generally increasing throughout the United
States, the rate of construction and development of new, more efficient electric
generation facilities may exceed increases in demand in some regional electric
markets. The start-up of new facilities in the regional markets in which we have
facilities could increase competition in the wholesale power market in those
regions, which could harm our business, results of operations and financial
condition. Also, industry restructuring in regions in which we have substantial
operations could affect our operations in a manner that is difficult to predict,
since the effects will depend on the form and timing of the restructuring.
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GENERAL RISKS OF OUR REGULATED OPERATIONS
WE ARE EXPOSED TO NUCLEAR GENERATION RISK.
Through our affiliates, Indiana Michigan Power Company and TCC, we have
interests in four nuclear generating units, which interests equal 2,740 MW, or
7% of our generation capacity. We are, therefore, also subject to the risks of
nuclear generation, which include the following:
- the potential harmful effects on the environment and human health
resulting from the operation of nuclear facilities and the storage,
handling and disposal of radioactive materials;
- limitations on the amounts and types of insurance commercially available
to cover losses that might arise in connection with our nuclear
operations or those of others in the United States;
- uncertainties with respect to contingencies and assessment amounts if
insurance coverage is inadequate; and
- uncertainties with respect to the technological and financial aspects of
decommissioning nuclear plants at the end of their licensed lives.
The Nuclear Regulatory Commission (NRC) has broad authority under federal
law to impose licensing and safety-related requirements for the operation of
nuclear generation facilities. In the event of non-compliance, the NRC has the
authority to impose fines or shut down a unit, or both, depending upon its
assessment of the severity of the situation, until compliance is achieved.
Revised safety requirements promulgated by the NRC could necessitate substantial
capital expenditures at nuclear plants such as ours. In addition, although we
have no reason to anticipate a serious nuclear incident at our plants, if an
incident did occur, it could harm our results of operations or financial
condition. A major incident at a nuclear facility anywhere in the world could
cause the NRC to limit or prohibit the operation or licensing of any domestic
nuclear unit.
THE DIFFERENT REGIONAL POWER MARKETS IN WHICH WE COMPETE OR WILL COMPETE IN
THE FUTURE HAVE CHANGING TRANSMISSION REGULATORY STRUCTURES, WHICH COULD
AFFECT OUR PERFORMANCE IN THESE REGIONS.
Our results are likely to be affected by differences in the market and
transmission regulatory structures in various regional power markets. Problems
or delays that may arise in the formation and operation of new regional
transmission organizations, or "RTOs", may restrict our ability to sell power
produced by our generating capacity to certain markets if there is insufficient
transmission capacity otherwise available. The rules governing the various
regional power markets may also change from time to time which could affect our
costs or revenues. Because it remains unclear which companies will be
participating in the various regional power markets, or how RTOs will develop or
what regions they will cover, we are unable to assess fully the impact that
these power markets may have on our business.
In May 2002, we announced an agreement with the Pennsylvania-New
Jersey-Maryland RTO (the PJM) Interconnection to pursue terms for participation
in its RTO. Final agreements are expected to be negotiated. In July 2002, the
FERC tentatively approved the decision of our subsidiaries located in the east
to join PJM subject to certain conditions being met. The performance of these
conditions is only partially under our control. In October 2002, PJM announced
that our east subsidiaries and other unaffiliated utilities planned to turn
functional control of their transmission lines over to PJM during the first
quarter of 2003 and are scheduled to become full members by May 2003. Virginia
has adopted legislation that prevents us and certain other unaffiliated
utilities operating in Virginia from joining any RTO, including PJM, before July
2004. Management is unable to predict the ultimate effect of this Virginia
legislation.
Two of our western subsidiaries are members of the Southwest Power Pool
(the "SPP"). The SPP had agreed to merge with the Midwest Independent
Transmission System Operator (MISO), an independent operator of transmission
assets in the Midwest. MISO and SPP recently announced that they were no longer
pursuing their merger. Our two subsidiaries provided notice that they would
withdraw from the SPP after October 31, 2002. This action was taken to provide
our subsidiaries additional flexibility in deciding which RTO they will
ultimately join.
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Management is unable to predict the outcome of these transmission
regulatory actions and proceedings or their impact on the timing and operation
of RTOs, our transmission operations or future results of operations and cash
flows.
WE ARE SUBJECT TO REGULATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF
1935.
Our system is subject to the jurisdiction of the SEC under PUHCA. The rules
and regulations under PUHCA impose a number of restrictions on the operations of
registered holding company systems. These restrictions include a requirement
that the SEC approve in advance securities issuances, sales and acquisitions of
utility assets, sales and acquisitions of securities of utility companies and
acquisitions of other businesses. PUHCA also generally limits the operations of
a registered holding company to a single integrated public utility system, plus
additional energy-related businesses. PUHCA rules limit the dividends that our
subsidiaries may pay from unearned surplus.
OUR MERGER WITH CSW MAY ULTIMATELY BE FOUND TO VIOLATE PUHCA.
We acquired CSW in a merger completed on June 15, 2000. Among the more
significant assets we acquired as a result of the merger were four additional
domestic electric utility companies -- PSO, SWEPCo, TCC (formerly, CPL) and TNC
(formerly, WTU). On January 18, 2002, the U.S. Court of Appeals for the District
of Columbia ruled that the SEC's June 14, 2000 order approving the merger failed
to properly find that the merger meets the requirements of PUHCA and sent the
case back to the SEC for further review. Specifically, the court told the SEC to
revisit its conclusion that the merger met PUHCA's requirement that the electric
utilities be "physically interconnected" and confined to a "single area or
region."
We believe that the merger meets the requirements of PUHCA and expect the
matter to be resolved favorably. We intend to fully cooperate with the staff of
the SEC in supplementing the record, if necessary, to ensure the merger complies
with PUHCA. We can give no assurance, however, that: (i) the SEC or any
applicable court review will find that the merger complies with PUHCA, or (ii)
the SEC or any applicable court review will not impose material adverse
conditions on us in order to find that the merger complies with PUHCA. If the
merger were ultimately found to violate PUHCA, it may require us to take
remedial actions or divest assets which may harm our results of operations or
financial condition.
RISKS RELATED TO MARKET, ECONOMIC OR INTERNATIONAL FINANCIAL VOLATILITY
WE ARE SUBJECT TO RISKS ASSOCIATED WITH A CHANGING ECONOMIC ENVIRONMENT.
In response to the occurrence of several recent events, including the
September 11, 2001 terrorist attack on the United States, the ongoing war
against terrorism by the United States, and the bankruptcy of Enron Corp., the
financial markets have been disrupted in general, and the availability and cost
of capital for our business and that of our competitors has been at least
temporarily harmed. In addition, following the bankruptcy of Enron Corp., the
credit ratings agencies initiated a thorough review of the capital structure and
earnings power of energy companies, including us. These events could constrain
the capital available to our industry and could limit our access to funding for
our operations. Our business is capital intensive, and achievement of our growth
targets is dependent, at least in part, upon our ability to access capital at
rates and on terms we determine to be attractive. If our ability to access
capital becomes significantly constrained, our interest costs will likely
increase and our financial condition could be harmed and future results of
operations could be significantly harmed.
The insurance industry has also been disrupted by these events. As a
result, the availability of insurance covering risks we and our competitors
typically insure against has decreased. In addition, the insurance we are able
to obtain has higher deductibles and higher premiums.
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DOWNGRADES IN OUR CREDIT RATINGS COULD NEGATIVELY AFFECT OUR ABILITY TO ACCESS
CAPITAL AND/OR TO CONDUCT OUR POWER AND GAS TRADING ACTIVITIES.
On February 10, 2003, Moody's downgraded our senior unsecured long-term
debt rating to Baa3 (with stable outlook) from Baa2 and our short-term debt
rating to P-3 (with stable outlook) from P-2. On March 7, 2003, Standard &
Poor's Ratings Service downgraded their rating on our senior unsecured debt to
BBB (with stable outlook) from BBB+ (CreditWatch with negative implications) and
confirmed their rating on our commercial paper of A-2 (with stable outlook). On
March 10, 2003, Fitch Ratings, Inc. downgraded their rating on our senior
unsecured debt to BBB (with stable outlook) from BBB+ and confirmed their rating
on our commercial paper of F2 (with stable outlook). As a result, our access to
the commercial paper market may be limited and our short-term borrowing costs
may increase.
To strengthen our financial condition, we have announced plans to, among
other things, (1) cut operating and capital expenses, and (2) dispose of
non-core assets. If the reduction of operating and capital expenses is too
severe it may adversely impact the profitable operation of assets, including
generating plants, which could adversely impact our results of operations or
financial condition.
Further, our plans to dispose of non-core assets may not succeed. If we
sell such non-core assets below their book value, we would sustain additional
impairments. If we retain such assets due to unfavorable market conditions for
their sale, we are exposed to the risk of sustaining additional operating
losses. There can be no assurance that we will successfully dispose of our
non-core assets as planned.
Our power trading activity relies on the investment grade ratings of the
senior unsecured debt of our utility subsidiaries. Our gas trading activity
relies on the investment grade ratings of our senior unsecured debt. While
Moody's recently downgraded several of those ratings, our senior unsecured debt
ratings and those of our utility subsidiaries continue to be investment grade.
Most of our counterparties require the creditworthiness of an investment grade
entity to stand behind transactions. If our ratings or those of our utility
subsidiaries were to decline below investment grade, we would likely have to
deposit cash or cash related instruments, which would reduce our results of
operations and impact our financial condition.
OUR OPERATING RESULTS MAY FLUCTUATE ON A SEASONAL AND QUARTERLY BASIS.
Electric power generation is generally a seasonal business. In many parts
of the country, demand for power peaks during the hot summer months, with market
prices also peaking at that time. In other areas, power demand peaks during the
winter. As a result, our overall operating results in the future may fluctuate
substantially on a seasonal basis. The pattern of this fluctuation may change
depending on the nature and location of facilities we acquire and the terms of
power sale contracts we enter into. In addition, we have historically sold less
power, and consequently earned less income, when weather conditions are milder.
We expect that unusually mild weather in the future could diminish our results
of operations and harm our financial condition.
CHANGES IN TECHNOLOGY MAY SIGNIFICANTLY AFFECT OUR BUSINESS BY MAKING OUR
POWER PLANTS LESS COMPETITIVE.
A key element of our business model is that generating power at central
power plants achieves economies of scale and produces power at relatively low
cost. There are other technologies that produce power, most notably fuel cells,
microturbines, windmills and photovoltaic (solar) cells. It is possible that
advances in technology will reduce the cost of alternative methods of producing
power to a level that is competitive with that of most central power station
electric production. If this were to happen and if these technologies achieved
economies of scale, our market share could be eroded, and the value of our power
plants could be reduced. Changes in technology could also alter the channels
through which retail electric customers buy power, thereby harming our financial
results.
RISKS OF DOING BUSINESS OUTSIDE THE UNITED STATES
We currently own and may acquire and/or dispose of material energy-related
investments and projects outside the United States. The economic and political
conditions in certain countries where we have interests
S-18
or in which we may explore development, acquisition or investment opportunities
present risks of delays in construction and interruption of business, as well as
risks of war, expropriation, nationalization, renegotiation, trade sanctions or
nullification of existing contracts and changes in law or tax policy, that are
greater than in the United States. The uncertainty of the legal environment in
certain foreign countries in which we develop or acquire projects or make
investments could make it more difficult to obtain non-recourse project or other
financing on suitable terms, could adversely affect the ability of certain
customers to honor their obligations with respect to such projects or
investments and could impair our ability to enforce our rights under agreements
relating to such projects or investments.
Operations in foreign countries also can present currency exchange rate and
convertibility, inflation and repatriation risk. In certain countries in which
we develop or acquire projects, or make investments, economic and monetary
conditions and other factors could affect our ability to convert our earnings
denominated in foreign currencies to United States dollars or other hard
currencies or to move funds offshore from such countries. Furthermore, the
central bank of any such country may have the authority in certain circumstances
to suspend, restrict or otherwise impose conditions on foreign exchange
transactions or to approve distributions to foreign investors. Although we
intend to structure our power purchase agreements, joint venture agreements and
other project revenue agreements to provide for payments or contributions to be
made in, or indexed to, United States dollars or a currency freely convertible
into United States dollars, there can be no assurance that we will be able to
achieve this structure in all cases or that a power purchaser or other customer
will be able to obtain sufficient United States dollars or other hard currency
or that available United States dollars will be allocated to pay such
obligations or make such contributions.
CHANGES IN COMMODITY PRICES MAY INCREASE OUR COST OF PRODUCING POWER OR
DECREASE THE AMOUNT WE RECEIVE FROM SELLING POWER, HARMING OUR FINANCIAL
PERFORMANCE.
We are heavily exposed to changes in the price and availability of coal
because most of our generating capacity is coal-fired. We have contracts of
varying durations for the supply of coal for most of our existing generation
capacity, but as these contracts end, we may not be able to purchase coal on
terms as favorable as the current contracts.
We also own natural gas-fired facilities, which increases our exposure to
the more volatile market prices of natural gas.
Changes in the cost of coal or natural gas and changes in the relationship
between those costs and the market prices of power will affect our financial
results. Since the price we obtain for electricity may not change at the same
rate as the change in coal or natural gas costs, we may be unable to pass on the
changes in costs to our customers. In addition, the price we can charge our
retail customers in some jurisdictions are capped and our fuel recovery
mechanisms in other states are frozen for various periods of time.
In addition, actual power prices and fuel costs will differ from those
assumed in financial projections used to initially value our trading and
marketing transactions, and those differences may be material. As a result, our
financial results may be diminished in the future as those transactions are
marked to market.
AT TIMES, DEMAND FOR POWER COULD EXCEED OUR SUPPLY CAPACITY.
We are currently obligated to supply power in parts of eleven states. From
time to time the demand for power required to meet these obligations could
exceed our available generation capacity. If this occurs, we would have to buy
power on the market. We may not always have the ability to pass these costs on
to our customers because some of the states we operate in do not allow us to
increase our rates in response to increased fuel cost charges. Since these
situations most often occur during periods of peak demand, it is possible that
the market price for power at that time would be very high. Unlike the cooler
weather over the summer of 2000, the hotter-than-normal summer of 1999 saw
market prices for power in regions in which certain of our regulated utility
subsidiaries have supply obligations peak in excess of $5,000 per megawatt hour.
Utilities that did not own or purchase sufficient available capacity during
those periods incurred significant losses in sourcing incremental power. Even if
a supply shortage was brief, we could suffer substantial losses that could
diminish our results of operations.
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RISKS RELATED TO ENVIRONMENTAL REGULATION
OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT, AND THE COST
OF COMPLIANCE WITH FUTURE ENVIRONMENTAL LAWS COULD HARM OUR CASH FLOW AND
PROFITABILITY.
Our operations are subject to extensive federal, state and local
environmental statutes, rules and regulations relating to air quality, water
quality, waste management, natural resources and health and safety. Compliance
with these legal requirements requires us to commit significant capital toward
environmental monitoring, installation of pollution control equipment, emission
fees and permits at all of our facilities. These expenditures have been
significant in the past and we expect that they will increase in the future.
Costs of compliance with environmental regulations could harm our industry, our
business and our results of operations and financial position, especially if
emission and/or discharge limits are tightened, more extensive permitting
requirements are imposed, additional substances become regulated and the number
and types of assets we operate increase.
WE ANTICIPATE THAT WE WILL INCUR CONSIDERABLE CAPITAL COSTS FOR COMPLIANCE.
Most of our generating capacity is coal burning. We plan to install new
emissions control equipment and may be required to upgrade existing equipment,
purchase emissions allowances or reduce operations. We expect to spend
approximately $1.3 to 2 billion in connection with the installation of emission
control equipment at our facilities to comply with the new NOx rule (of which
approximately $843 million had been expended through December 31, 2002), the
Section 126 Rule and certain environmental requirements of Texas. Moreover,
environmental laws are subject to change, which may materially increase our
costs of compliance or accelerate the timing of these capital expenditures. Our
compliance strategy, although reasonably based on the information available to
us today, may not successfully address the relevant standards and
interpretations of the future.
GOVERNMENTAL AUTHORITIES MAY ASSESS PENALTIES ON US FOR FAILURES TO COMPLY
WITH ENVIRONMENTAL LAWS AND REGULATIONS.
If we fail to comply with environmental laws and regulations, even if
caused by factors beyond our control, that failure may result in the assessment
of civil or criminal penalties and fines against us. Recent lawsuits by the EPA
and various states filed against us highlight the environmental risks faced by
generating facilities, in general, and coal-fired generating facilities, in
particular.
Since 1999, we have been involved in litigation regarding generating plant
emissions under the Clean Air Act. Federal EPA and a number of states alleged
that we and eleven unaffiliated utilities modified certain units at coal-fired
generating plants in violation of the Clean Air Act. Federal EPA filed
complaints against certain AEP subsidiaries in U.S. District Court for the
Southern District of Ohio. A separate lawsuit initiated by certain special
interest groups was consolidated with the Federal EPA case. The alleged
modification of the generating units occurred over a 20 year period.
If these actions are resolved against us, substantial modifications of our
existing coal-fired power plants would be required. In addition, we could be
required to invest significantly in additional emission control equipment,
accelerate the timing of capital expenditures, pay penalties and/or halt
operations. Moreover, our results of operations and financial position could be
reduced due to the consequent distraction of management and the expense of
ongoing litigation.
Other parties have settled similar lawsuits. An unaffiliated utility which
operates certain plants jointly owned by CSPCo reached a tentative agreement to
settle litigation regarding generating plant emissions under the Clean Air Act.
Negotiations are continuing and a settlement could impact the operation of
certain of the jointly owned plants. Until a final settlement is reached, CSPCo
will be unable to determine the settlement's impact on its jointly owned
facilities and its future results of operations and cash flows.
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WE ARE UNLIKELY TO BE ABLE TO PASS ON THE COST OF ENVIRONMENTAL COMPLIANCE TO
OUR CUSTOMERS.
Most of our contracts with wholesale customers do not permit us to recover
additional capital and other costs incurred by us to comply with new
environmental regulations. Due to the deregulation of generation in Texas, Ohio
and Virginia, we cannot recover through rates additional capital and other costs
incurred by us to comply with new environmental regulations with respect to our
generation previously regulated in those jurisdictions. As a result of rate
freezes in effect in Michigan and Indiana (expiring January 1, 2005) we
generally cannot recover through rates additional capital and other costs
incurred by us to comply with new environmental regulations with respect to our
generation subject to those jurisdictions.
USE OF PROCEEDS
We estimate that we will receive net proceeds from the sale of our Senior
Notes in this offering of approximately $297,219,000, after deducting expenses
and offering discounts.
Credit Suisse First Boston LLC and UBS Warburg LLC purchased $250,000,000
aggregate principal amount of AEP's outstanding 5.50% Putable Callable Notes,
Series B (the "Outstanding Notes") on May 15, 2003. We have agreed to accept the
Outstanding Notes as partial consideration for the Senior Notes and to receive
cash for the remaining purchase price of the Senior Notes. Following this
offering, we will retire the Outstanding Notes and we expect to use the
remaining proceeds to pay down short-term debt.
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CAPITALIZATION
The following table sets forth our capitalization as of March 31, 2003:
- on an actual basis; and
- on an as adjusted basis to give effect to the sale of our Senior Notes,
after deducting the underwriting discounts and estimated offering
expenses, and the expected use of proceeds described herein.
Since March 31, 2003, there has not been any material change in the
information set forth below, except as may be described elsewhere in this
prospectus supplement, in the accompanying prospectus or in any of the documents
incorporated by reference therein. The allocation of net proceeds between
short-term debt and long-term debt under "As Adjusted" is an estimate and may
differ from the actual use of proceeds. You should read the information in this
table along with the financial information included or incorporated by reference
in this prospectus supplement and the accompanying prospectus.
MARCH 31, 2003
---------------------
ACTUAL AS ADJUSTED
------- -----------
(IN MILLIONS)
(UNAUDITED)
Debt:
Short-term debt, including commercial paper............... $ 239 $ 229
Long-term debt, including current maturities.............. 12,132 12,182
Equity Unit Senior Notes.................................. 376 376
------- -------
Total debt............................................. 12,747 12,787
------- -------
Certain subsidiary obligated, mandatorily redeemable,
preferred securities of subsidiary trusts holding
solely junior subordinated debentures of such
subsidiaries........................................... 321 321
------- -------
Minority interest in finance subsidiary................... 759 759
------- -------
Cumulative preferred stock of subsidiaries.................. 144 144
------- -------
Common shareholders' equity:
Common stock, par value $6.50; 600 million shares
authorized, 403,993,412 shares issued at 3/31/03
(8,999,992 shares were held in treasury at 3/31/03).... 2,626 2,626
Paid-in capital........................................... 4,175 4,175
Accumulated other comprehensive income (loss)............. (602) (602)
Retained earnings......................................... 2,238 2,238
------- -------
Total common shareholders' equity...................... 8,437 8,437
------- -------
Total capitalization................................. $22,408 $22,448
------- -------
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AMERICAN ELECTRIC POWER COMPANY, INC.
The following discussion highlights certain important facts regarding us
and our subsidiaries and does not contain all of the information that may be
important to you. We encourage you to read the documents referred to in the
accompanying prospectus under "Where You Can Find More Information," which
contain more complete descriptions of us and our business.
American Electric Power Company, Inc. (AEP) is one of the largest
investor-owned public utility companies in the United States. We provide,
directly or indirectly, generation, transmission and distribution services to
almost five million customers in eleven states (Arkansas, Indiana, Kentucky,
Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West
Virginia) through our utility operations.
Our portfolio of assets includes:
- 38,000 megawatts of generating capacity, the largest complement of
generation in the United States;
- 38,000 miles of transmission lines;
- 186,000 miles of distribution lines that support delivery of electricity
to our customers' premises;
- Substantial coal transportation assets (7,000 railcars, 1,800 barges, 37
tug boats and two coal handling terminals with 20 million tons of annual
capacity);
- 6,400 miles of gas pipelines in Louisiana and Texas with 128 billion
cubic feet of gas storage facilities; and
- 4,000 megawatts of generating capacity in the U.K. and other minor
international investments.
BUSINESS STRATEGY
Our business is focused on utility operations in the United States, which
tend to offer more stable and relatively predictable earnings and cash flow. We
are continuing to reduce trading in markets where we do not have assets and will
focus instead on ensuring maximum value for our assets by selling output in
excess of our utility needs. This asset optimization approach has long been part
of our strategy as an active seller of excess power in the Midwest. We remain
focused on credit quality and liquidity.
Our strategy for the core business of utility operations is to:
- Maintain moderate but steady earnings growth;
- Maximize the value of transmission assets and protect revenue stream
through RTO membership;
- Continue process improvement to maintain distribution service quality
while enhancing financial performance;
- Optimize generation assets through enhanced availability and sale of
excess capacity; and
- Manage the regulatory process to maximize retention of earnings and
operational improvement.
UTILITY OPERATIONS
Our electric utility subsidiaries, which do business as "American Electric
Power," have traditionally provided electric service, consisting of generation,
transmission and distribution, on an integrated basis to their retail customers.
For discussion on the status of deregulation, see "Restructuring" below.
These operating subsidiaries are:
APPROXIMATE MW
OPERATING SUBSIDIARY SERVICE TERRITORY CUSTOMERS OWNED/LEASED
-------------------- ----------------- ----------- ------------
AEP Generating Company............... N/A(1) N/A(1) 1,300
AEP Texas Central Company (TCC)(2)... Southern Texas 690,000(3) 4,497(4)
AEP Texas North Company (TNC)(5)..... West and Central Texas 189,000(3) 1,392(6)
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APPROXIMATE MW
OPERATING SUBSIDIARY SERVICE TERRITORY CUSTOMERS OWNED/LEASED
-------------------- ----------------- ----------- ------------
Appalachian Power Company (APCo)..... Southwestern Virginia and Southern 925,000 5,850
West Virginia
Columbus Southern Power Company...... Ohio 689,000 2,595
Indiana Michigan Power Company
(I&M).............................. Northern and Eastern Indiana and 571,000 4,416
Southwestern Michigan
Kentucky Power Company............... Eastern Kentucky 174,000 1,060
Kingsport Power Company.............. Kingsport, TN and a portion of 46,000 None(7)
Northeastern Tennessee
Ohio Power Company (OPCo)............ Northwestern, East Central, 702,000 8,520
Eastern and Southern Sections of
Ohio
Public Service Company of Oklahoma... Eastern and Southwestern Oklahoma 505,000 4,228
Southwestern Electric Power
Company............................ Northeastern Texas, Northwestern 437,000 4,487
Louisiana and Western Arkansas
Wheeling Power Company............... Northern West Virginia 41,000 None(8)
---------------
(1) AEP Generating Company sells power to Indiana Michigan Power Company and
Kentucky Power Company.
(2) Formerly Central Power and Light Company.
(3) Via approximately two dozen unaffiliated retail electricity providers.
(4) TCC has applied to the Public Utility Commission of Texas (PUCT) to sell
these assets. Includes 1,721 MW TCC has deactivated.
(5) Formerly West Texas Utilities Company.
(6) Includes 390 MW TNC has deactivated.
(7) Purchases its electric power requirements from APCo.
(8) Purchases its electric power requirements from OPCo.
REGULATION
Our public utility subsidiaries' retail rates and certain other matters are
subject to traditional regulation by state utility commissions in Arkansas,
Indiana, Kentucky, Louisiana, Oklahoma, Tennessee and West Virginia. In these
states the rates of our public utility subsidiaries are generally based on the
cost of providing traditional bundled electric service (i.e., generation,
transmission and distribution service). The states of Ohio, Texas and Virginia
are transitioning from bundled cost-of-service based rates for electric service
to unbundled cost-of-service based rates for transmission and distribution
service and market pricing for and/or customer choice of generation. Retail
sales in Michigan, while still regulated, are now provided at unbundled rates.
The traditional regulatory framework reflects specified fuel costs as part
of bundled or unbundled rates or incorporates fuel adjustment clauses in a
utility's rates and tariffs. Fuel adjustment clauses permit periodic adjustments
to fuel cost recovery from customers and therefore provide protection against
exposure to fuel cost changes. However, recovery of increased fuel costs (i) is
no longer provided for in Ohio and (ii) may be limited in the states of West
Virginia and Michigan, which have capped or suspended clauses. There will be a
true-up proceeding in 2004 in Texas to quantify and reconcile unreconciled fuel
costs as well as the amount of stranded costs for TCC, the capacity auction
true-up, the price-to-beat clawback component and other regulatory assets
associated with the generating assets located in the ERCOT area of Texas that
were not previously securitized. The findings from the true-up proceeding will
have the practical result of increasing or decreasing the transmission and
distribution rates that we charge in the ERCOT area of Texas.
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A summary of the rate regulation of each of our major utility subsidiaries
is contained in the table below:
PROPOSED
UTILITY STATES RATES AND FUEL CLAUSES RTO
------- ------ ---------------------- --------
AEP Texas Central................. TX Transmission and distribution rates not ERCOT
capped or frozen; true-up proceeding in 2004
AEP Texas North................... TX Transmission and distribution rates not ERCOT
capped or frozen; true-up proceeding in 2004
Appalachian Power................. VA Rates capped until as late as July 1, 2007; PJM
active fuel clause
WV Rates and fuel fixed indefinitely pursuant
to stipulation
Columbus Southern Power........... OH Rates frozen through 2005 with no fuel PJM
adjustment; distribution rates frozen
through 2008
Indiana Michigan Power............ IN Rates capped until January 1, 2005 and fuel PJM
capped until March 1, 2004
MI Rates capped until January 1, 2005 and fuel
capped until January 1, 2004
Kentucky Power.................... KY Rates frozen until June 15, 2003; active PJM
fuel clause
Ohio Power........................ OH Rates frozen through 2005 with no fuel PJM
adjustment; distribution rates frozen
through 2007
Public Service of Oklahoma........ OK Rates capped until January 1, 2003 (under SPP
review); active fuel clause
Southwestern Electric Power....... AR Rates capped until June 15, 2003; active SPP
fuel clause
LA Rates capped until June 15, 2005 (under
review); active fuel clause
TX Rates frozen until June 15, 2003; active
fuel clause
Our subsidiaries are also subject to regulation by the FERC under the
Federal Power Act. I&M and TCC are subject to regulation by the Nuclear
Regulatory Commission under the Atomic Energy Act of 1954, as amended, with
respect to the operation of the Cook Plant and the South Texas Project (STP),
respectively. We are subject to the broad regulatory provisions of the Public
Utility Holding Company Act of 1935, as amended, administered by the SEC.
UTILITY OPERATIONS AND OTHER INVESTMENTS
Our public utility subsidiaries currently own approximately 38,000 MW of
domestic generation. A substantial portion of the electric power generated at
our generating stations is sold, at bundled or unbundled generation,
transmission and distribution rates, to retail customers of our utility
subsidiaries in their service territories. The remaining portion is sold on a
wholesale basis to non-affiliated electric utilities, municipalities, electric
cooperatives, other wholesale customers and power marketers.
Our public utility subsidiaries own and operate transmission and
distribution lines and other facilities to deliver electric power. Most of the
transmission and distribution services are sold, in combination with electric
power, to retail customers of our public utility subsidiaries in their service
territories. These sales are made at rates established by the state utility
commissions of the states in which these subsidiaries operate. In addition, for
the three months ended March 31, 2003, there were approximately $111 million in
third-party transmission revenues. The FERC regulates and approves the rates for
wholesale transmission transactions.
In October 2002, we announced plans to reduce our exposure to energy
trading markets and to downsize our trading and wholesale marketing operations.
We are continuing to reduce trading in markets where we do
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not have assets and have focused instead on ensuring maximum value for our
assets by selling excess output. Going forward, we plan for our energy trading
and marketing operations to be limited to risk management around our assets and
focused in regions where we own assets.
Our wholesale electric power transactions in the United States are
conducted principally through our public utility subsidiaries. Other wholesale
transactions are conducted principally through AEP Energy Services, Inc. and AEP
Resources, Inc. These operations use and manage the following assets:
- Natural gas pipeline, storage and processing facilities;
- Coal mines and related facilities; and
- Barge, rail and other fuel transportation related assets.
These utility and non-utility operations consist of the following:
- Through our public utility subsidiaries, the generation and sale of power
at wholesale regulated in certain instances by FERC;
- Trading and marketing energy commodities in transactions limited to risk
management around assets used or managed by our wholesale operations,
including electric power, natural gas, natural gas liquids, oil, coal,
and SO(2) allowances in North America and, where applicable, Europe; and
- Entering into long-term transactions to buy or sell capacity, energy, and
ancillary services of electric generating facilities, either existing or
to be constructed, at various locations in North America and Europe.
In September 2002, we indicated to ERCOT our intent to deactivate 16
gas-fired power plants (eight TCC plants and eight TNC plants). ERCOT
subsequently conducted reliability studies that determined that seven plants
(four TCC plants and three TNC plants) would be required to ensure reliability
of the electricity grid. As a result of these studies, ERCOT and AEP entered
into "reliability must run" (RMR) agreements to continue operation of these
seven plants. The RMR agreements expired in December 2002 but have been renewed
for all but two units of these plants. With ERCOT's approval, we are proceeding
with our planned deactivation of the remaining nine plants.
TCC intends to sell all of its power generation assets in an effort to
determine its level of stranded costs in accordance with the Texas restructuring
law and PUCT regulations. The assets we intend to sell have a generating
capacity of 4,497 MW and include eight gas-fired plants, one coal-fired plant,
TCC's interest in another coal-fired plant, a hydroelectric facility and TCC's
interest in STP.
RESTRUCTURING
Our public utility subsidiaries, like many other electric utilities, have
traditionally provided electric generation and energy delivery, consisting of
transmission and distribution services, as a single product to their retail
customers. Legislation has been enacted in Michigan, Ohio, Texas and Virginia
that allows for customer choice of generation supplier. These measures generally
allow competition in the generation and sale of electric power, but not in its
transmission and distribution. Although customer choice legislation has been
enacted in Arkansas, Oklahoma and West Virginia, such legislation has been
repealed in Arkansas, delayed indefinitely in Oklahoma and has not been
implemented in West Virginia.
Each of our Ohio utility subsidiaries currently operates as a functionally
separated electric utility company and no longer charges bundled rates for its
retail sales of electricity. Distribution rates for our Ohio utility
subsidiaries are approved by The Public Utilities Commission of Ohio and
transmission rates are approved by the FERC. We have sought regulatory approval
to legally separate the transmission and distribution assets of our Ohio utility
subsidiaries from their generation assets pursuant to Ohio restructuring
legislation. However, we are presently determining the regulatory feasibility of
complying with Ohio restructuring legislation through continued functional
separation. Assuming regulatory compliance, it is currently our intention that
our Ohio utility subsidiaries remain functionally separated. Similarly, each of
our Texas utility subsidiaries in ERCOT also currently operates as a
functionally separated electric utility
S-26
company with distribution and, for the most part, transmission rates that
continue to be set by the PUCT and with generation rates that are not set by the
PUCT. We have sought regulatory approval to legally separate the generation
assets of our Texas utility subsidiaries from their transmission and
distribution assets as required by Texas restructuring legislation.
Additionally, TCC intends to sell its generation assets in order to accurately
determine TCC's stranded costs in accordance with Texas restructuring
legislation and PUCT regulation. Transition rules for Michigan and Virginia do
not require legal separation. Due in part to difficulties in deregulating other
markets, deregulation appears unlikely for the foreseeable future in the other
states in which we operate.
INVESTMENTS
We have made certain investments in telecommunications, international
energy and other concerns. In 2002, we wrote down substantially all of the value
of certain of these investments and significant portions of the value of certain
other of these investments to reflect deterioration in market conditions. We are
evaluating our portfolio of non-regulated assets and plan to sell assets that
are no longer core to our business strategy.
We also consummated the following transactions related to foreign
investments in 2002:
- The sale of SEEBOARD GROUP plc, an electricity supply and distribution
company in the United Kingdom serving 2,000,000 customers and covering
3,000 square miles of service territory; and
- The sale of CitiPower Pty., a retail electricity and gas supply and
distribution subsidiary in Australia serving 240,000 customers.
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SUPPLEMENTAL DESCRIPTION OF THE SENIOR NOTES
The following description of the particular terms of the Senior Notes
supplements and in certain instances replaces the description of the general
terms and provisions of the Senior Notes under "Description of the Notes" in the
accompanying Prospectus. We will issue the Senior Notes under an Indenture,
dated as of May 1, 2001, between us and The Bank of New York, as Trustee, as
supplemented and amended and as to be further supplemented and amended.
The Senior Notes will be our unsecured and unsubordinated obligations
ranking equally with our other outstanding unsecured and unsubordinated
indebtedness. At March 31, 2003, we had approximately $2.3 billion outstanding
unsecured and unsubordinated indebtedness. The Indenture contains no
restrictions on the amount of additional indebtedness that we may issue.
PRINCIPAL AMOUNT, MATURITY, INTEREST AND PAYMENT
The Senior Notes will initially be issued in an aggregate principal amount
of $300,000,000. We may, without consent of the holders of the Senior Notes,
issue additional notes having the same ranking, interest rate, maturity and
other terms as the Senior Notes. The Senior Notes will be a single series of
notes under the Indenture.
The Senior Notes will mature and become due and payable, together with any
accrued and unpaid interest, on June 1, 2015 and will bear interest at the rate
of 5.25% per year from May 20, 2003 until June 1, 2015. The Senior Notes are not
subject to any sinking fund provision.
Interest on each Senior Note will be payable semi-annually in arrears on
each June 1 and December 1 and at redemption, if any, or maturity. The initial
interest payment date is December 1, 2003. Each payment of interest shall
include interest accrued through the day before such interest payment date.
Interest on the Senior Notes will be computed on the basis of a 360-day year
consisting of twelve 30-day months.
We will pay interest on the Senior Notes (other than interest payable at
redemption, if any, or maturity) in immediately available funds to the owners of
the Senior Notes as of the Regular Record Date (as defined below) for each
interest payment date.
We will pay the principal of the Senior Notes and any premium and interest
payable at redemption, if any, or at maturity in immediately available funds at
the office of The Bank of New York, 101 Barclay Street in New York, New York.
If any interest payment date, redemption date or the maturity is not a
Business Day (as defined below), we will pay all amounts due on the next
succeeding Business Day and no additional interest will be paid.
The "Regular Record Date" will be the close of business on the May 15 or
November 15 prior to the relevant interest payment date, whether or not a
Business Day.
"Business Day" means any day that is not a day on which banking
institutions in New York City are authorized or required by law or regulation to
close.
OPTIONAL REDEMPTION
We may redeem the Senior Notes at our option at any time, upon no more than
60 and not less than 30 days' notice by mail. We may redeem the Senior Notes
either as a whole or in part at a redemption price equal to the greater of (1)
100% of the principal amount of the Senior Notes being redeemed and (2) the sum
of the present values of the remaining scheduled payments of principal and
interest on the Senior Notes being redeemed (excluding the portion of any such
interest accrued to the date of redemption) discounted (for purposes of
determining present value) to the redemption date on a semi-annual basis
(assuming a 360-day year consisting of twelve 30-day months) at the Treasury
Rate (as defined below) plus 35 basis points, plus, in each case, accrued
interest thereon to the date of redemption.
"Treasury Rate" means, with respect to any redemption date for the Senior
Notes, the rate per year equal to the semi-annual equivalent yield to maturity
of the Comparable Treasury Issue, assuming a price for the
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Comparable Treasury Issue (expressed as a percentage of its principal amount)
equal to the Comparable Treasury Price for such redemption date.
"Comparable Treasury Issue" means the United States Treasury security
selected by a Senior Independent Investment Banker as having a maturity
comparable to the remaining term of the Senior Notes that would be utilized, at
the time of selection and in accordance with customary financial practice, in
pricing new issues of corporate debt securities of a comparable maturity to the
remaining term of the Senior Notes.
"Comparable Treasury Price" means, with respect to any redemption date for
the Senior Notes, (1) the average of the bid and asked prices for the Comparable
Treasury Issue (expressed in each case as a percentage of its principal amount)
on the third Business Day preceding such redemption date, as set forth in the
daily statistical release (or any successor release) published by the Federal
Reserve Bank of New York and designated "Composite 3:30 p.m. Quotations for U.S.
Government Securities" or (2) if such release (or any successor release) is not
published or does not contain such prices on such third Business Day, the
Reference Treasury Dealer Quotation for such redemption date.
"Independent Investment Banker" means one of the Reference Treasury Dealers
appointed by us and reasonably acceptable to the Trustee.
"Reference Treasury Dealer" means a primary U.S. Government Securities
Dealer selected by us and reasonably acceptable to the Trustee.
"Reference Treasury Dealer Quotation" means, with respect to the Reference
Treasury Dealer and any redemption date, the average, as determined by the
Trustee, of the bid and asked prices for the Comparable Treasury Issue
(expressed in each case as a percentage of its principal amount) quoted in
writing to the Trustee by such Reference Treasury Dealer at or before 5:00 p.m.,
New York City time, on the third Business Day preceding such redemption date.
RESTRICTIVE COVENANTS RELATING TO THE SENIOR NOTES
LIMITATION UPON LIENS ON STOCK OF CERTAIN SUBSIDIARIES
For so long as any Senior Notes remain outstanding, we will not create or
incur or allow any of our subsidiaries to create or incur any pledge or security
interest on any of the capital stock of a Public Utility Subsidiary held by us
or one of our subsidiaries or a Significant Subsidiary.
For purposes of this covenant, a Public Utility Subsidiary means, at any
particular time, a direct or indirect subsidiary of ours that, as a substantial
part of its business, distributes or transmits electric energy to retail or
wholesale customers at rates or tariffs that are regulated by either a state or
Federal regulatory authority.
For purposes of this covenant, Significant Subsidiary means, at any
particular time, any direct subsidiary of ours whose consolidated gross assets
or consolidated gross revenues (having regard to our direct beneficial interest
in the shares, or the like, of that subsidiary) represent at least 25% of our
consolidated gross assets or our consolidated gross revenues.
LIMITATION UPON MERGERS, CONSOLIDATIONS AND SALE OF ASSETS
Nothing in the Indenture or the Senior Notes prevents us from consolidating
or merging with or into, or selling or otherwise disposing of all or
substantially all of our property to another entity, provided that (1) we agree
to obtain a supplemental indenture pursuant to which the surviving entity or
transferee agrees to assume our obligations relating to all outstanding debt
securities issued under the Indenture and (2) the surviving entity or transferee
is organized under the laws of the United States, any state thereof or the
District of Columbia.
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ADDITIONAL INFORMATION
For additional important information about the Senior Notes, including: (i)
additional information about the terms of the Senior Notes, (ii) general
information about the Indenture and the trustee, and (iii) a description of
events of default under the Indenture, see "Description of the Notes" in the
accompanying prospectus.
S-30
UNDERWRITING
Subject to the terms and conditions of an underwriting agreement dated the
date hereof between us and Credit Suisse First Boston LLC and UBS Warburg LLC
(the "Underwriters"), we have agreed to sell to the Underwriters named below and
each of the Underwriters has severally and not jointly agreed to purchase from
us the respective principal amount of Senior Notes set forth opposite its name
below:
PRINCIPAL AMOUNT
UNDERWRITER OF SENIOR NOTES
----------- ----------------
Credit Suisse First Boston LLC.............................. $150,000,000
UBS Warburg LLC............................................. 150,000,000
------------
$300,000,000
============
In the underwriting agreement, the Underwriters have agreed, subject to the
terms and conditions set forth therein, to purchase all of the Senior Notes
offered hereby if any of the Senior Notes are purchased.
The expenses associated with the offer and sale of the Senior Notes are
expected to be approximately $300,000.
The Underwriters propose to offer the Senior Notes to the public at the
initial public offering prices set forth on the cover page of this prospectus
supplement and to certain dealers at such prices less a concession not in excess
of .400% per Senior Note. The Underwriters may allow, and such dealers may
reallow, a discount not in excess of .250% per Senior Note to certain other
dealers. After the initial public offering of the Senior Notes, the public
offering price, concession and discount may be changed.
Prior to this offering, there has been no public market for the Senior
Notes. The Senior Notes will not be listed on any securities exchange. The
Underwriters have advised us that they intend to make a market in the Senior
Notes. The Underwriters will have no obligation to make a market in the Senior
Notes, however, and may cease market making activities, if commenced, at any
time. No assurance can be given as to the liquidity of the trading market for
the Senior Notes or that an active public market for the Senior Notes will
develop. If an active public trading market for the Senior Notes does not
develop, the market price and liquidity of the Senior Notes may be adversely
affected.
We have agreed to indemnify the Underwriters against certain liabilities,
including liabilities under the Securities Act of 1933, as amended.
In connection with the offering, the Underwriters may engage in
transactions that stabilize, maintain or otherwise affect the price of the
Senior Notes. These transactions may include over-allotment and stabilizing
transactions and purchases to cover syndicate short positions created in
connection with the offering. Stabilizing transactions consist of certain bids
or purchases for the purposes of preventing or retarding a decline in the market
price of the Senior Notes and syndicate short positions involving the sale by
the Underwriters of a greater number of Senior Notes than they are required to
purchase from us in the offering. The Underwriters also may impose a penalty
bid, whereby selling concessions allowed to syndicate members or other broker
dealers in respect of the securities sold in the offering for their account may
be reclaimed by the syndicate if such Senior Notes are repurchased by the
syndicate in stabilizing or covering transactions. Any of these activities may
cause the price of the Senior Notes to be higher than the price that might
otherwise prevail in the open market; and these activities, if commenced, may be
discontinued at any time. These transactions may be effected in the
over-the-counter market or otherwise.
We have agreed, during the period of 30 days from the date of the
underwriting agreement, not to sell, offer to sell, grant any option for the
sale of, or otherwise dispose of any Senior Notes, any security convertible into
or exchangeable into or exercisable for Senior Notes or any debt securities
substantially similar to the Senior Notes (except for the Senior Notes issued
pursuant to the underwriting agreement) without the prior written consent of the
Underwriters.
The Underwriters and certain of their affiliates have performed investment
banking, advisory, general financing and commercial banking services for us and
our subsidiaries from time to time for which they have
S-31
received customary fees and expenses. The Underwriters may, from time to time in
the future, engage in transactions with and perform services for us and our
subsidiaries in the ordinary course of their business.
The Underwriters will make the Senior Notes available for distribution on
the Internet through a proprietary Web site and/or third-party system operated
by Market Axess Inc., an Internet-based communications technology provider.
Market Axess Inc. is providing the system as a conduit for communications
between the Underwriters and their customers and is not a party to any
transactions. We do not believe that Market Axess Inc., will function as an
underwriter or agent of the issuer nor do we believe that Market Axess Inc. will
act as a broker for any customer of the Underwriters. Market Axess Inc., a
registered broker-dealer, will receive compensation from the Underwriters based
on transactions the Underwriters conduct through the system. The Underwriters
will make the Senior Notes available to their customers through the Internet
distributions, whether made through a proprietary or third-party system, on the
same terms as distributions made through other channels.
Because 10% or more of the proceeds of this offering, not including
underwriter compensation, may be paid to affiliates of certain of the
Underwriters who are members of the National Association of Securities Dealers,
Inc. (NASD), this offering is being conducted pursuant to NASD Conduct Rule
2710(c)(8).
NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the Senior Notes in Canada is being made only on a
private placement basis exempt from the requirement that we prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of Senior Notes are made. Any resale of the Senior Notes in Canada must
be made under applicable securities laws, which will vary depending on the
relevant jurisdiction, and which may require resales to be made under available
statutory exemptions or under a discretionary exemption granted by the
applicable Canadian securities regulatory authority. Purchasers are advised to
seek legal advice prior to any resale of the Senior Notes.
REPRESENTATION OF PURCHASERS
By purchasing Senior Notes in Canada and accepting a purchase confirmation
a purchaser is representing to us and the dealer from whom the purchase
confirmation is received that
- the purchaser is entitled under applicable provincial securities laws to
purchase the Senior Notes without the benefit of a prospectus qualified
under those securities laws,
- where required by law, the purchaser is purchasing as principal and not
as agent, and
- the purchaser has reviewed the text above under Resale Restrictions.
RIGHTS OF ACTION -- ONTARIO PURCHASERS ONLY
Under Ontario securities legislation, a purchaser who purchases a security
offered by this prospectus during the period of distribution will have a
statutory right of action for damages, or while still the owner of the Senior
Notes, for rescission against us in the event that this prospectus contains a
misrepresentation. A purchaser will be deemed to have relied on the
misrepresentation. The right of action for damages is exercisable not later than
the earlier of 180 days from the date the purchaser first had knowledge of the
facts giving rise to the cause of action and three years from the date on which
payment is made for the Senior Notes. The right of action for rescission is
exercisable not later than 180 days from the date on which payment is made for
the Senior Notes.
If a purchaser elects to exercise the right of action for rescission, the
purchaser will have no right of action for damages against us. In no case will
the amount recoverable in any action exceed the price at which the Senior Notes
were offered to the purchaser and if the purchaser is shown to have purchased
the securities with knowledge of the misrepresentation, we will have no
liability. In the case of an action for damages we will not
S-32
be liable for all or any portion of the damages that are proven not to represent
the depreciation in value of the Senior Notes as a result of the
misrepresentation relied upon. These rights are in addition to and without
derogation from, any other rights or remedies available at law to an Ontario
purchaser. The foregoing is a summary of the rights available to an Ontario
purchaser. Ontario purchasers should refer to the complete text of the relevant
statutory provisions.
ENFORCEMENT OF LEGAL RIGHTS
All of our directors and officers as well as the experts named herein may
be located outside of Canada and, as a result, it may not be possible for
Canadian purchasers to effect service of process within Canada upon us or those
persons. All or a substantial portion of our assets and the assets of those
persons may be located outside of Canada and, as a result, it may not be
possible to satisfy a judgment against us or those persons in Canada or to
enforce a judgment obtained in Canadian courts against us or those persons
outside of Canada.
TAXATION AND ELIGIBILITY FOR INVESTMENT
Canadian purchasers of Senior Notes should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the Senior
Notes in their particular circumstances and about the eligibility of the senior
notes for investment by the purchaser under relevant Canadian Legislation.
LEGAL MATTERS
Certain legal matters with respect to this offering of our Senior Notes
will be passed on for us by Thomas G. Berkemeyer, Esq., Associate General
Counsel of American Electric Power Service Corporation, one of our affiliates,
or William E. Johnson, Esq., Senior Counsel of American Electric Power Service
Corporation and Simpson Thacher & Bartlett, New York, New York and for the
Underwriters by Dewey Ballantine LLP, New York, New York. From time to time,
Dewey Ballantine LLP acts as counsel to our affiliates for some matters.
EXPERTS
The consolidated financial statements of the Company and subsidiaries
incorporated in this prospectus supplement by reference from the Company's
Current Report on Form 8-K dated May 14, 2003 have been audited by Deloitte &
Touche LLP, independent auditors, as stated in their reports which are
incorporated herein by reference (which reports express unqualified opinions and
include explanatory paragraphs relating to the adoption of SFAS 142 "Goodwill
and Other Intangible Assets", the recording of certain impairments of goodwill,
long-lived assets and other investments in the fourth quarter of 2002, and to
the realignment of segments for financial reporting purposes).
The consolidated financial statement schedules of the Company and
subsidiaries incorporated by reference in this prospectus supplement from the
Company's Annual Report on Form 10-K/A have been audited by Deloitte & Touche
LLP, independent auditors, as stated in their report, which is also incorporated
herein by reference.
The aforementioned reports have been so incorporated in reliance upon such
firm given their authority as experts in accounting and auditing.
S-33
PROSPECTUS
AMERICAN ELECTRIC POWER COMPANY, INC.
1 RIVERSIDE PLAZA
COLUMBUS, OHIO 43215
(614) 223-1000
$1,500,000,000
UNSECURED NOTES
TERMS OF SALE
The following terms may apply to the notes that we may sell at one or more
times. A prospectus supplement or pricing supplement will include the final
terms for each note. If we decide to list upon issuance any note or notes on a
securities exchange, a prospectus supplement or pricing supplement will identify
the exchange and state when we expect trading could begin.
- Maturity date or dates
- Fixed or floating interest rate
- Remarketing features
- Certificate or book-entry form
- Subject to redemption
- Not convertible, amortized or subject to a sinking fund
- Interest paid on fixed rate notes quarterly or semi-annually
- Interest paid on floating rate notes daily, weekly, monthly, quarterly,
semi-annually, or annually
- Issued in multiples of a minimum denomination
THE NOTES HAVE NOT BEEN APPROVED BY THE SECURITIES AND EXCHANGE COMMISSION
("SEC") OR ANY STATE SECURITIES COMMISSION, NOR HAVE THESE ORGANIZATIONS
DETERMINED THAT THIS PROSPECTUS IS ACCURATE OR COMPLETE. ANY REPRESENTATION TO
THE CONTRARY IS A CRIMINAL OFFENSE.
The date of this prospectus is April 19, 2001.
THE COMPANY
We are a public utility holding company that owns, directly or indirectly,
all of the outstanding common stock of our domestic electric utility
subsidiaries and varying degrees of other subsidiaries. Substantially all of our
operating revenues derive from the furnishing of electric service. In addition,
in recent years we have been pursuing various unregulated business opportunities
in the U.S. and worldwide. We were incorporated under the laws of New York in
1906 and reorganized in 1925. Our principal executive offices are located at 1
Riverside Plaza, Columbus, Ohio 43215, and our telephone number is (614)
223-1000.
We own, directly or indirectly, all the outstanding common stock of the
following operating public utility companies: Appalachian Power Company, Central
Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company,
Public Service Company of Oklahoma, Southwestern Electric Power Company, West
Texas Utilities Company and Wheeling Power Company. These operating public
utility companies supply electric service in portions of Arkansas, Indiana,
Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and
West Virginia. We also own all of the outstanding common stock of American
Electric Power Service Corporation, which provides accounting, administrative,
information systems, engineering, financial, legal, maintenance and other
services to us and our subsidiaries.
On June 15, 2000, one of our wholly-owned subsidiaries merged with and into
Central and South West Corporation, a publicly owned electric utility holding
company whose public utility companies supply electric service in portions of
Arkansas, Louisiana, Oklahoma and Texas. As a result of the merger, the
shareholders of Central and South West Corporation became shareholders of us and
we became the sole owner of Central and South West Corporation.
WHERE YOU CAN FIND MORE INFORMATION
This prospectus is part of a registration statement we filed with the SEC.
We also file annual, quarterly and special reports and other information with
the SEC. You may read and copy any document we file at the SEC's Public
Reference Room at 450 Fifth Street, N. W., Washington, D.C. 20549. Please call
the SEC at 1-800-SEC-0330 for further information on the public reference rooms.
You may also examine our SEC filings through the SEC's web site at
http://www.sec.gov.
The SEC allows us to "incorporate by reference" the information we file
with them, which means that we can disclose important information to you by
referring you to those documents. The information incorporated by reference is
considered to be part of this prospectus, and later information that we file
with the SEC will automatically update and supersede this information. We
incorporate by reference the document listed below and any future filings made
with the SEC under Sections 13(a), 13(c), 14, or 15(d) of the Securities
Exchange Act of 1934 until we sell all the notes.
Annual Report on Form 10-K for the year ended December 31, 2000.
You may request a copy of these filings, at no cost, by writing or
telephoning us at the following address:
Mr. G. C. Dean
American Electric Power Service Corporation
1 Riverside Plaza
Columbus, Ohio 43215
(614) 223-1000
You should rely only on the information incorporated by reference or
provided in this prospectus or any supplement. We have not authorized anyone
else to provide you with different information. We are not making an offer of
these notes in any state where the offer is not permitted. You should not assume
that the information in this prospectus or any supplement is accurate as of any
date other than the date on the front of those documents.
1
PROSPECTUS SUPPLEMENTS
We will provide information to you about the notes in up to three separate
documents that progressively provide more detail: (a) this prospectus provides
general information some of which may not apply to your notes, (b) the
accompanying prospectus supplement provides more specific terms of your notes,
and (c) the pricing supplement, if any, provides the final terms of your notes.
It is important for you to consider the information contained in this
prospectus, the prospectus supplement, and the pricing supplement, if any, in
making your investment decision.
RATIO OF EARNINGS TO FIXED CHARGES
The Ratio of Earnings to Fixed Charges for each of the periods indicated is
as follows:
TWELVE MONTHS
PERIOD ENDED RATIO
------------- -----
December 31, 1996........................................... 2.22
December 31, 1997........................................... 2.22
December 31, 1998........................................... 2.25
December 31, 1999........................................... 2.14
December 31, 2000........................................... 1.59
For current information on the Ratio of Earnings to Fixed Charges, please
see our most recent Form 10-K and 10-Q. See Where You Can Find More Information.
USE OF PROCEEDS
The net proceeds from the sale of the notes will be used for general
corporate purposes relating to our business. Unless stated otherwise in a
prospectus supplement, these purposes include redeeming or repurchasing
outstanding debt, replenishing working capital, financing our subsidiaries'
ongoing construction and maintenance programs. If we do not use the net proceeds
immediately, we temporarily invest them in short-term, interest-bearing
obligations. At April 3, 2001, our outstanding short-term debt was
$3,691,000,000.
DESCRIPTION OF THE NOTES
GENERAL
We will issue the notes under an Indenture to be entered into by us and the
Trustee, The Bank of New York. This prospectus briefly outlines some provisions
of the Indenture. If you would like more information on these provisions, you
should review the Indenture and any supplemental indentures or company orders
that we have filed or will file with the SEC. See Where You Can Find More
Information on how to locate these documents. You may also review these
documents at the Trustee's offices at 101 Barclay Street, New York, New York.
The Indenture does not limit the amount of notes that may be issued. The
Indenture permits us to issue notes in one or more series or tranches upon the
approval of our board of directors and as described in one or more company
orders or supplemental indentures. Each series of notes may differ as to their
terms. The Indenture also gives us the ability to reopen a previous issue of a
series of notes and issue additional notes of such series.
Because we are a holding company, the claims of creditors of our
subsidiaries will have a priority over our equity rights and the rights of our
creditors (including the holders of the notes) to participate in the assets of
the subsidiary upon the subsidiary's liquidation.
2
The notes are unsecured and will rank equally with all our unsecured
unsubordinated debt. For current information on our debt outstanding see our
most recent Form 10-K and 10-Q. See Where You Can Find More Information.
The notes will be denominated in U.S. dollars and we will pay principal and
interest in U.S. dollars. Unless an applicable pricing or prospectus supplement
states otherwise, the notes will not be subject to any conversion, amortization,
or sinking fund. We expect that the notes will be "book-entry," represented by a
permanent global note registered in the name of The Depository Trust Company, or
its nominee. We reserve the right, however, to issue note certificates
registered in the name of the noteholders.
In the discussion that follows, whenever we talk about paying principal on
the notes, we mean at maturity or redemption. Also, in discussing the time for
notices and how the different interest rates are calculated, all times are New
York City time and all references to New York mean the City of New York, unless
otherwise noted.
The Indenture does not protect holders of the notes if we engage in a
highly leveraged transaction.
The following terms may apply to each note as specified in the applicable
pricing or prospectus supplement and the note:
REDEMPTIONS
If we issue redeemable notes, we may redeem such notes at our option unless
an applicable pricing or prospectus supplement states otherwise. The pricing or
prospectus supplement will state the terms of redemption. We may redeem notes in
whole or in part by delivering written notice to the noteholders no more than
60, and not less than 30, days prior to redemption. If we do not redeem all the
notes of a series at one time, the Trustee selects the notes to be redeemed in a
manner it determines to be fair.
REMARKETED NOTES
If we issue notes with remarketing features, an applicable pricing or
prospectus supplement will describe the terms for the notes including: interest
rate, remarketing provisions, our right to purchase or redeem notes, the
holders' right to tender notes, and any other provisions.
BOOK-ENTRY NOTES -- REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND
PRINCIPAL
Unless otherwise stated in a prospectus supplement, book-entry notes of a
series will be issued in the form of a global note that the Trustee will deposit
with The Depository Trust Company, New York, New York ("DTC"). This means that
we will not issue note certificates to each holder. One or more global notes
will be issued to DTC who will keep a computerized record of its participants
(for example, your broker) whose clients have purchased the notes. The
participant will then keep a record of its clients who purchased the notes.
Unless it is exchanged in whole or in part for a note certificate, a global note
may not be transferred, except that DTC, its nominees, and their successors may
transfer a global note as a whole to one another.
Beneficial interests in global notes will be shown on, and transfers of
global notes will be made only through, records maintained by DTC and its
participants.
DTC has provided us the following information: DTC is a limited-purpose
trust company organized under the New York Banking Law, a "banking organization"
within the meaning of the New York Banking Law, a member of the United States
Federal Reserve System, a "clearing corporation" within the meaning of the New
York Uniform Commercial Code and a "clearing agency" registered under the
provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds
securities that its participants ("Direct Participants") deposit with DTC. DTC
also records the settlement among Direct Participants of securities
transactions, such as transfers and pledges, in deposited securities through
computerized records for Direct Participant's accounts. This eliminates the need
to exchange note certificates. Direct Participants include securities brokers
and dealers, banks, trust companies, clearing corporations and certain other
organizations.
3
Other organizations such as securities brokers and dealers, banks and trust
companies that work through a Direct Participant also use DTC's book-entry
system. The rules that apply to DTC and its participants are on file with the
SEC.
A number of its Direct Participants and the New York Stock Exchange, Inc.,
The American Stock Exchange, Inc. and the National Association of Securities
Dealers, Inc. own DTC.
We will wire principal and interest payments to DTC's nominee. We and the
Trustee will treat DTC's nominee as the owner of the global notes for all
purposes. Accordingly, we, the Trustee and (any paying agent) will have no
direct responsibility or liability to pay amounts due on the global notes to
owners of beneficial interests in the global notes.
It is DTC's current practice, upon receipt of any payment of principal or
interest, to credit Direct Participants' accounts on the payment date according
to their respective holdings of beneficial interests in the global notes as
shown on DTC's records. In addition, it is DTC's current practice to assign any
consenting or voting rights to Direct Participants whose accounts are credited
with notes on a record date. The customary practices between the participants
and owners of beneficial interests will govern payments by participants to
owners of beneficial interests in the global notes and voting by participants,
as is the case with notes held for the account of customers registered in
"street name." However, payments will be the responsibility of the participants
and not of DTC, the Trustee or us.
According to DTC, the foregoing information with respect to DTC has been
provided to the Direct Participants and other members of the financial community
for informational purposes only and is not intended to serve as a
representation, warranty or contract modification of any kind.
Notes represented by a global note will be exchangeable for note
certificates with the same terms in authorized denominations only if:
DTC notifies us that it is unwilling or unable to continue as
depositary or if DTC ceases to be a clearing agency registered under
applicable law and a successor depositary is not appointed by us within 90
days; or
we determine not to require all of the notes of a series to be
represented by a global note and notify the Trustee of our decision.
NOTE CERTIFICATES -- REGISTRATION, TRANSFER, AND PAYMENT OF INTEREST AND
PRINCIPAL
If we issue note certificates, they will be registered in the name of the
noteholder. The notes may be transferred or exchanged, pursuant to
administrative procedures in the indenture, without the payment of any service
charge (other than any tax or other governmental charge) by contacting the
paying agent. Payments on note certificates will be made by check.
INTEREST RATE
The interest rate on the notes will either be fixed or floating. The
interest paid will include interest accrued to, but excluding, the date of
maturity or redemption. Interest is generally payable to the person in whose
name the note is registered at the close of business on the record date before
each interest payment date. Interest payable at maturity or redemption, however,
will be payable to the person to whom principal is payable.
If we issue a note after a record date but on or prior to the related
interest payment date, we will pay the first interest payment on the interest
payment date after the next record date. We will pay interest payments by check
or wire transfer, at our option.
FIXED RATE NOTES
A pricing or prospectus supplement will designate the record dates, payment
dates and the fixed rate of interest payable on a note. We will pay interest
quarterly or semi-annually, and upon maturity or redemption.
4
Unless an applicable pricing or prospectus supplement states otherwise, if any
payment date falls on a day that is not a business day, we will pay interest on
the next business day and no additional interest will be paid. Interest payments
will be the amount of interest accrued to, but excluding, each payment date.
Interest will be computed using a 360-day year of twelve 30-day months.
FLOATING RATE NOTES
Each floating rate note will have an interest rate formula. The applicable
prospectus supplement or pricing supplement will state the initial interest rate
or interest rate formula on each note effective until the first interest reset
date. The applicable pricing or prospectus supplement will state the method and
dates on which the interest rate will be determined, reset and paid.
EVENTS OF DEFAULT
"Event of Default" means any of the following:
- failure to pay for three business days the principal of (or premium, if
any, on) any note of a series when due and payable;
- failure to pay for 30 days any interest on any note of any series when
due and payable;
- failure to perform any other requirements in such notes, or in the
Indenture in regard to such notes, for 90 days after notice;
- certain events of bankruptcy or insolvency; or
- any other event of default specified in a series of notes.
An Event of Default for a particular series of notes does not necessarily
mean that an Event of Default has occurred for any other series of notes issued
under the Indenture. If an Event of Default occurs and continues, the Trustee or
the holders of at least 33% of the principal amount of the notes of the series
affected may require us to repay the entire principal of the notes of such
series immediately ("Repayment Acceleration"). In most instances, the holders of
at least a majority in aggregate principal amount of the notes of the affected
series may rescind a previously triggered Repayment Acceleration. However, if we
cause an Event of Default because we have failed to pay (unaccelerated)
principal, premium, if any, or interest, Repayment Acceleration may be rescinded
only if we have first cured our default by depositing with the Trustee enough
money to pay all (unaccelerated) past due amounts and penalties, if any.
The Trustee must within 90 days after a default occurs, notify the holders
of the notes of the series of default unless such default has been cured or
waived. We are required to file an annual certificate with the Trustee, signed
by an officer, concerning any default by us under any provisions of the
Indenture.
Subject to the provisions of the Indenture relating to its duties in case
of default, the Trustee shall be under no obligation to exercise any of its
rights or powers under the Indenture at the request, order or direction of any
holders unless such holders offer the Trustee reasonable indemnity. Subject to
the provisions for indemnification, the holders of a majority in principal
amount of the notes of any series may direct the time, method and place of
conducting any proceedings for any remedy available to, or exercising any trust
or power conferred on, the Trustee with respect to such notes.
MODIFICATION OF INDENTURE
Under the Indenture, our rights and obligations and the rights of the
holders of any notes may be changed. Any change affecting the rights of the
holders of any series of notes requires the consent of the holders of not less
than a majority in aggregate principal amount of the outstanding notes of all
series affected by the change, voting as one class. However, we cannot change
the terms of payment of principal or interest, or a reduction in the percentage
required for changes or a waiver of default, unless the holder consents. We may
issue additional series of notes and take other action that does not affect the
rights of holders of any series by executing supplemental indentures without the
consent of any noteholders.
5
CONSOLIDATION, MERGER OR SALE
We may merge or consolidate with any entity or sell substantially all of
our assets as an entirety as long as the successor or purchaser (i) is organized
and existing under the laws of the United States, any state thereof or the
District of Columbia and (ii) expressly assumes the payment of principal,
premium, if any, and interest on the notes.
LEGAL DEFEASANCE
We will be discharged from our obligations on the notes of any series at
any time if:
- we deposit with the Trustee sufficient cash or government securities to
pay the principal, interest, any premium and any other sums due to the
stated maturity date or a redemption date of the note of the series, and
- we deliver to the Trustee an opinion of counsel stating that the federal
income tax obligations of noteholders of that series will not change as a
result of our performing the action described above.
If this happens, the noteholders of the series will not be entitled to the
benefits of the Indenture except for registration of transfer and exchange of
notes and replacement of lost, stolen or mutilated notes.
COVENANT DEFEASANCE
We will be discharged from our obligations under any restrictive covenant
applicable to the notes of a particular series if we perform both actions
described above. See Legal Defeasance. If this happens, any later breach of that
particular restrictive covenant will not result in Repayment Acceleration. If we
cause an Event of Default apart from breaching that restrictive covenant, there
may not be sufficient money or government obligations on deposit with the
Trustee to pay all amounts due on the notes of that series. In that instance, we
would remain liable for such amounts.
GOVERNING LAW
The Indenture and notes of all series will be governed by the laws of the
State of New York.
CONCERNING THE TRUSTEE
We and our affiliates use or will use some of the banking services of the
Trustee in the normal course of business.
PLAN OF DISTRIBUTION
We may sell the notes (a) through agents; (b) through underwriters or
dealers; or (c) directly to one or more purchasers.
BY AGENTS
Notes may be sold on a continuing basis through agents designated by us.
The agents will agree to use their reasonable efforts to solicit purchases for
the period of their appointment.
Unless the pricing or prospectus supplement states otherwise, the notes
will be sold to the public at 100% of their principal amount. Agents will
receive commissions from .125% to .750% of the principal amount per note
depending on the maturity of the note they sell.
The Agents will not be obligated to make a market in the notes. We cannot
predict the amount of trading or liquidity of the notes.
6
BY UNDERWRITERS
If underwriters are used in the sale, the underwriters will acquire the
notes for their own account. The underwriters may resell the notes in one or
more transactions, including negotiated transactions, at a fixed public offering
price or at varying prices determined at the time of sale. The obligations of
the underwriters to purchase the notes will be subject to certain conditions.
The underwriters will be obligated to purchase all the notes of the series
offered if any of the notes are purchased. Any initial public offering price and
any discounts or concessions allowed or re-allowed or paid to dealers may be
changed from time to time.
DIRECT SALES
We may also sell notes directly. In this case, no underwriters or agents
would be involved.
GENERAL INFORMATION
Underwriters, dealers, and agents that participate in the distribution of
the notes may be underwriters as defined in the Securities Act of 1933 (the
"Act"), and any discounts or commissions received by them from us and any profit
on the resale of the notes by them may be treated as underwriting discounts and
commissions under the Act.
We may have agreements with the underwriters, dealers and agents to
indemnify them against certain civil liabilities, including liabilities under
the Act.
Underwriters, dealers and agents may engage in transactions with, or
perform services for, us or our affiliates in the ordinary course of their
businesses.
LEGAL OPINIONS
Our counsel, Simpson Thacher & Bartlett, New York, NY, and one of our
lawyers will each issue an opinion about the legality of the notes for us. Dewey
Ballantine LLP, New York, NY will issue an opinion for the agents or
underwriters. From time to time, Dewey Ballantine LLP acts as counsel to our
affiliates for some matters.
EXPERTS
The financial statements of the Company and its subsidiaries (including
Central and South West Corporation and its subsidiaries, as of December 31,
2000, and for the year then ended) and the related financial statement schedule
incorporated in this prospectus by reference from the Company's Annual Report on
Form 10-K for the year ended December 31, 2000 have been audited by Deloitte &
Touche LLP, as stated in their reports dated February 26, 2001 (which report on
the financial statements expresses an unqualified opinion and includes an
explanatory paragraph referring to the restatement of the 1999 and 1998
financial statements to give retroactive effect to the conforming change in the
method of accounting for vacation pay accruals), which are incorporated herein
by reference.
The financial statements of Central and South West Corporation and its
subsidiaries (excluding CSW UK Holdings and CSW UK Finance Company), as of
December 31, 1999 and 1998, and for each of the two years ended December 31,
1999, have been audited by Arthur Andersen LLP, as stated in their reports,
which are incorporated herein by reference. The financial statements of CSW UK
Holdings, as of December 31, 1999, and the year then ended, and CSW UK Finance
Company, as of December 31, 1998, and the year then ended, have been audited by
KPMG Audit Plc, as stated in their reports, which are incorporated herein by
reference.
Such financial statements of the Company and its subsidiaries are included
herein in reliance upon the respective reports of such firms given upon their
authority as experts in accounting and auditing. All of the foregoing firms are
independent auditors.
7
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$300,000,000
AMERICAN ELECTRIC POWER COMPANY, INC.
5.25% SENIOR NOTES, SERIES D, DUE 2015
AMERICAN ELECTRIC POWER LOGO
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PROSPECTUS SUPPLEMENT
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May 15, 2003
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