GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
Term Meaning
---- -------
AEPES . . . . . . . AEP Energy Services, a non-regulated subsidiary of AEP.
AEGCo or AEPGEN . . AEP Generating Company, a domestic generating subsidiary
of AEP.
AEP, AEP Co., Inc
or the Company. . American Electric Power Company, Inc.
AEP System or
the System. . . . The American Electric Power System, an integrated electric
utility system.
AEPR. . . . . . . . AEP Resources, Inc., a non-regulated subsidiary of AEP.
AEPSC or the Service
Corporation . . . American Electric Power Service Corporation, a service
subsidiary of AEP.
AFUDC . . . . . . . Allowance for funds used during construction. Defined in
regulatory systems of accounts as the net cost of
borrowed funds used for construction and a reasonable
rate of return on other funds when so used.
APCo. . . . . . . . Appalachian Power Company, a domestic electric utility
subsidiary of AEP.
Btu's . . . . . . . British Thermal Unit
CAAA. . . . . . . . The Clean Air Act Amendments of 1990.
CERCLA. . . . . . . The Comprehensive Environmental Response, Compensation
and Liability Act.
Also called Superfund.
COLI. . . . . . . . Corporate owned life insurance.
Conoco. . . . . . . An energy subsidiary of DuPont.
Cook Plant. . . . . The Donald C. Cook Nuclear Plant, owned by I&M.
CSPCo . . . . . . . Columbus Southern Power Company, a domestic electric
utility subsidiary of AEP.
CSW . . . . . . . . Central and South West Corporation, an electric utility
holding company based in Dallas, Texas.
DOE . . . . . . . . United States Department of Energy.
D&P . . . . . . . . Duff & Phelps, LLC.
EFC . . . . . . . . Electric Fuel Component, a portion of rates for Ohio
companies designed to recover fuel costs.
EITF. . . . . . . . Emerging Issues Task Force of the FASB.
FASB. . . . . . . . Financial Accounting Standards Board.
Federal EPA . . . . United States Environmental Protection Agency.
FERC. . . . . . . . Federal Energy Regulatory Commission (an independent
commission within the DOE).
Gavin Plant . . . . A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Cheshire, Ohio.
I&M . . . . . . . . Indiana Michigan Power Company, a domestic electric
utility subsidiary of AEP.
IRS . . . . . . . . United States Internal Revenue Service.
KEPCo or KPCo . . . Kentucky Power Company, a domestic electric utility
subsidiary of AEP.
KGPCo . . . . . . . Kingsport Power Company, a domestic electric utility
subsidiary of AEP.
KPSC. . . . . . . . Kentucky Public Service Commission.
Kwh . . . . . . . . Kilowatthour.
MW or mw. . . . . . Megawatt, 1000 Kwh.
NAAQS . . . . . . . National Ambient Air Quality Standard as published and
revised by the Federal EPA.
NOx . . . . . . . . Nitrogen Oxide.
NRC . . . . . . . . Nuclear Regulatory Commission.
OPCo. . . . . . . . Ohio Power Company, a domestic electric utility
subsidiary of AEP.
OPEB. . . . . . . . Postretirement Benefits Other Than Pensions.
OVEC. . . . . . . . Ohio Valley Electric Corporation, an electric utility
company in which AEP and CSPCo own
a 44.2% equity interest.
PCBs. . . . . . . . Polychlorinated biphenyls.
PRP . . . . . . . . "Potentially Responsible Parties" as designated by the
Federal EPA.
PUCO. . . . . . . . The Public Utilities Commission of Ohio.
PUHCA or 1935 Act . Public Utility Holding Company Act of 1935, as amended.
Rockport Plant. . . A generating plant, consisting of two 1,300,000-kilowatt
coal-fired generating units, near Rockport, Indiana.
SEC . . . . . . . . Securities and Exchange Commission.
SEEBOARD. . . . . . CSW's UK distribution company.
SFAS. . . . . . . . Statement of Financial Accounting Standards.
SNF . . . . . . . . Spent Nuclear Fuel.
S&P . . . . . . . . Standard & Poor's.
Superfund . . . . . The Comprehensive Environmental Response, Compensation
and Liability Act. Also called CERCLA.
UK. . . . . . . . . United Kingdom.
UMWA. . . . . . . . United Mine Workers of America.
U.S.. . . . . . . . United States of America.
VaR . . . . . . . . Value at Risk, a model that measures interest rate market
risk exposure.
Virginia SCC or
VaSCC . . . . . . State Corporation Commission of Virginia.
WPCo. . . . . . . . Wheeling Power Company, a domestic electric utility
subsidiary of AEP.
Yorkshire . . . . . Yorkshire Electricity Group plc, a United Kingdom
distribution company of which 50% is indirectly owned
by AEP Resources, Inc.
Zimmer or
Zimmer Plant. . . Wm. H. Zimmer Generating Station, commonly owned by CSPCo,
Cincinnati Gas & Electric and Dayton Power & Light.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1997 1996 1995 1994 1993
INCOME STATEMENTS DATA (in millions):
Operating Revenues $6,161 $5,849 $5,670 $5,505 $5,269
Operating Income 984 1,008 965 932 929
Income Before Extraordinary Item 620 587 530 500 354
Extraordinary Loss -
UK Windfall Tax 109 - - - -
Net Income 511 587 530 500 354
December 31, 1997 1996 1995 1994 1993
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $19,597 $18,970 $18,496 $18,175 $17,712
Accumulated Depreciation
and Amortization 7,964 7,550 7,111 6,827 6,612
Net Electric
Utility Plant $11,633 $11,420 $11,385 $11,348 $11,100
Total Assets $16,615 $15,883 $15,900 $15,736 $15,359
Common Shareholders' Equity 4,677 4,545 4,340 4,229 4,151
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 47 90 148 233 268
Subject to Mandatory Redemption* 128 510 523 590 501
Long-term Debt* 5,424 4,884 5,057 4,980 4,995
Obligations Under Capital Leases* 538 414 405 400 284
*Including portion due within one year
Year Ended December 31, 1997 1996 1995 1994 1993
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item $ 3.28 $3.14 $2.85 $2.71 $1.92
Extraordinary Loss - UK Windfall Tax (0.58) - - - -
Net Income $ 2.70 $3.14 $2.85 $2.71 $1.92
Average Number of Shares
Outstanding (in thousands) 189,039 187,321 185,847 184,666 184,535
Market Price Range: High $ 52 $44-3/4 $40-5/8 $37-3/8 $40-3/8
Low 39-1/8 38-5/8 31-1/4 27-1/4 32
Year-end Market Price 51-5/8 41-1/8 40-1/2 32-7/8 37-1/8
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 88.7%(a) 76.5% 84.1% 88.6% 125.2%
Book Value per Share $24.62 $24.15 $23.25 $22.83 $22.50
(a) Dividend Payout Ratio before Extraordinary Loss - UK Windfall Tax is 73.1%.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND
FINANCIAL CONDITION
This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties. Among the factors that could
cause actual results to differ materially are: electric load and
customer growth; abnormal weather conditions; available sources and
costs of fuels and availability of generating capacity; the speed
and degree to which competition is introduced to our power
generation business, the terms of the transition to competition,
and its impact on rate structures; the ability to recover stranded
costs, new legislation and government regulations, the ability of
the Company to successfully reduce its costs including synergy
estimates; the degree to which the Company develops non-regulated
business ventures and their success; the economic climate and
growth in our service territory; inflationary trends, interest
rates and other risks.
In 1997 management took several major steps towards our growth
oriented goal of being America's Energy Partner and a global energy
and related services company. Construction of a 250-megawatt
generating station in China, jointly owned with two Chinese
partners, progressed on schedule and within budget. In April, the
Company and New Century Energies, Inc. acquired Yorkshire, a UK
distribution company. The Yorkshire investment is accounted for
using the equity method. A new power marketing business was
launched in July contributing significantly to our operating
revenues which surpassed $6 billion for the first time. A joint
venture with Conoco was announced in October that will provide
energy management services as well as financing of steam and
electric generation facilities at large commercial and industrial
plant sites including initially 16 Conoco and Dupont plant sites.
The completion of agreements for the joint venture companies and
the commencement of operations are expected in 1998.
In December 1997 AEP and Central and South West Corporation
agreed to merge. The merger is subject to approval by regulators
and shareholders. Completion of the merger is expected to occur in
the first half of 1999. CSW, a Dallas-based public utility holding
company, owns four domestic electric utility subsidiaries serving
1.7 million customers in portions of Texas, Oklahoma, Louisiana and
Arkansas and a regional electricity company in the UK. Other
international energy operations and non-utility subsidiaries owned
by CSW are involved in energy-related investments,
telecommunications, energy efficiency services and financial
transactions.
Income Before Extraordinary Loss Increases
AEP's 1997 income before an extraordinary loss, the one-time
UK Windfall Tax, increased 6% to $620 million or $3.28 per share
from $587 million or $3.14 per share in 1996. The increase was
primarily attributable to increased transmission service revenues,
reduced preferred stock dividends due to a redemption program and
an increase in nonoperating income from the April 1997 investment
in Yorkshire exclusive of the extraordinary loss. Net income
inclusive of the $109 million extraordinary loss decreased $76
million or 13% primarily due to the UK one-time windfall tax which
was based on a revision or recomputation of the original
privatization value of certain privatized utilities, including
Yorkshire.
For further details regarding changes in operating revenues
and expenses, taxes and nonoperating investment earnings in 1997
and 1996 see Results of Operations.
Business Outlook
The Company's ability to recover its costs as the industry
transitions to competition and as customer choice is more broadly
available is the most significant factor affecting its future.
Competition in the wholesale generation market continues to
intensify since the adoption of federal legislation in 1992 which
gave wholesale customers the right to choose their energy supplier
and the FERC orders issued in 1996 which forced open access
transmission. The introduction of competition and customer choice
for retail customers has been slow although activity has been
increasing. Federal legislation has been proposed to mandate
competition and customer choice at the retail level, and several
states have introduced or are considering similar legislation. All
of our states have initiatives to move to customer choice that
will phase-in or allow for a transition to competition, although
the timing is uncertain. The Company supports customer choice and
is proactively involved in discussions at both the state and
federal levels regarding how best to structure and transition to a
competitive marketplace.
As the cost of generation in the electric energy market evolves
from cost-of-service ratemaking to market-based pricing, many
complex issues must be resolved, including the recovery of stranded
costs. While FERC orders No. 888 and 889 provide, under certain
conditions, for recovery of stranded cost at the wholesale level,
the issue of stranded cost is unresolved at the much larger retail
level. The amount of any stranded costs we may experience depends
on the timing and extent to which direct competition is introduced
to our business and the then-existing market price of electricity.
Under the provisions of SFAS No. 71 "Accounting for the Effects
of Certain Types of Regulation," regulatory assets (deferred
expenses) and regulatory liabilities (deferred revenues) are
included in the consolidated balance sheets of regulated utilities
in accordance with regulatory actions and in order to match
expenses and revenues with cost-based rates. In order to maintain
net regulatory assets (net expense deferrals) on the balance sheet,
SFAS No. 71 requires that rates charged to customers be cost-based.
In the event a portion of AEP's business no longer meets the
requirements of SFAS No. 71, net regulatory assets would have to be
written off for that portion of the business. The provisions of
SFAS No. 71 and SFAS No. 101 "Accounting for the Discontinuance of
Application of Statement No. 71" never anticipated that
deregulation would include an extended transition period or that it
would provide for recovery of stranded costs after the transition
period. In July 1997 the FASB's EITF reached a consensus that the
application of SFAS No. 71 to a segment of a regulated electric
utility which is subject to a legislative plan to transition to
competition in that segment should cease when the legislation is
passed or an enabling rate order is issued containing sufficient
detail for the utility to reasonably determine what the plan would
entail. The EITF indicated that the cessation of application of
SFAS 71 would require that regulatory assets and impaired plant be
written off unless they are recoverable.
Although FERC orders No. 888 and 889 provide for competition
in the firm wholesale market, that market is a relatively small
part of our business and most of our firm wholesale sales are still
under cost-of-service contracts. As a result AEP's generation
business is still cost-based regulated and should remain so for the
near future pending the passage of enabling state legislation to
deregulate the generation business. We believe that enabling state
legislation should provide for the recovery of any generation-related net
regulatory assets and other reasonable stranded costs
from impaired generation assets. We are working with regulators,
customers and legislators to provide for recovery of these stranded
costs during a transition period in which rates are fixed or frozen
and electric utilities would take steps to achieve cost savings
which would be used to reduce or eliminate their stranded costs.
However, if in the future AEP's generation business were to no
longer be cost-based regulated and if it were not possible to
demonstrate probability of recovery of resultant stranded costs
including regulatory assets, results of operations, cash flows
and financial condition would be adversely affected.
Cost Containment and Process Improvements
Efforts continue by AEP to reduce the costs of its products and
services in order to maintain our competitiveness. Prior to 1997,
reviews of our major domestic processes led to decisions to
consolidate management and certain functions and operations and
improve certain major processes. While staff reductions and cost
savings resulting from the restructuring and improvements are
presently being achieved, expenses for new marketing, customer
services and modern efficient management information systems are
increasing to prepare for competition. In 1997 the costs of these
efforts to prepare for competition offset the savings from
restructuring.
In 1997, AEP also began installing a new unified customer
service system which is designed to support the request for
service, billings, accounts receivable, credit and collection
functions. AEP's new unified customer service system replaces a
30-year-old customer system and a nine-year-old transmission and
distribution work management system. Process improvement efforts
and expenditures to develop and implement the new customer service
system and similar efforts and expenditures to acquire, install and
enhance new client server-based accounting and budgeting/financial
planning software should produce further improvements and
efficiencies, enabling AEP to continue to offer its customers
excellent service at competitive prices.
Fuel Costs
AEP recognizes that it must continue to manage coal costs to
maintain its competitive position. Approximately 90% of AEP's
generation is coal fired and approximately 17% of the 53 million
tons of coal burned in 1997 were supplied by affiliated mines with
the remainder acquired under long-term contracts and purchases in
the spot market. As long-term contracts expire we are negotiating
with unaffiliated suppliers to lower coal costs. We intend to
continue to prudently supplement our long-term coal supplies with
spot market purchases as long as favorable spot market prices
exist.
In prior years we have agreed in our Ohio jurisdiction to
certain limitations on the recovery of affiliated coal costs. Our
analysis shows that we should be able to recover the Ohio
jurisdictional portion of the costs of our affiliated mining
operations including future mine closure costs. Management intends
to seek recovery of its non-Ohio jurisdictional portion of the
investment in and the liabilities and closing costs of our
affiliated mines estimated at $102 million after tax. However,
should it become apparent that these affiliated mining costs will
not be recovered from Ohio and/or non-Ohio jurisdictional
customers, the mines may have to be closed and future earnings and
possibly financial condition could be adversely affected. In
addition compliance with Phase II requirements of the CAAA, which
become effective in January 2000, could also cause the mining
operations to close. Unless the cost of any mine closure is
recovered either in regulated rates or as a stranded cost under a
plan to transition the generation business to competition, future
earnings, cash flows and possibly financial condition could be
adversely affected.
Nuclear Costs
Significant efforts have been made to enhance our competitiveness in
nuclear power generation and to improve our nuclear
organizational efficiency. In 1997 we continued to receive the
"excellence in performance" award from the Institute of Nuclear
Power Operations. Nuclear power plants have a major future
financial commitment to safely dispose of SNF and radioactive plant
components (i.e. to decommission the plant). It is difficult to
reduce nuclear generation costs since certain major cost components
are impacted by federal laws and NRC regulations.
The Nuclear Waste Policy Act of 1982 established federal
responsibility for the permanent off-site disposal of SNF and high-level
radioactive waste. By law we participate in the DOE's SNF
disposal program which is described in Note 4 of the Notes to
Consolidated Financial Statements. Since 1983 our customers have
paid $272 million for the disposal of nuclear fuel consumed at the
Cook Plant. Under the provisions of the Nuclear Waste Policy Act,
collections from customers are to provide the DOE with money to
build a repository for spent fuel. To date the federal government
has not made sufficient progress towards a permanent repository or
otherwise assuming responsibility for SNF. As long as there is a
delay in the construction of a government approved storage
repository for SNF, the cost of both temporary and permanent
storage will continue to increase. The cost to decommission the
Cook Plant is affected by both NRC regulations and the DOE's SNF
disposal program. Studies completed in 1997 estimate the cost to
decommission the Cook Plant range from $700 million to $1.152
billion in 1997 dollars. This estimate could escalate due to
uncertainty in the DOE's SNF disposal program and the length of
time that SNF may need to be stored at the plant site delaying
decommissioning. Presently we are recovering the estimated cost of
decommissioning the Cook Plant over its remaining life. However,
AEP's future results of operations, cash flows and possibly its
financial condition could be adversely affected if the cost of SNF
disposal and decommissioning continues to increase and cannot be
recovered.
On September 9 and 10, 1997, during a NRC architect engineer
design inspection, questions regarding the operability of certain
safety systems caused Company operations personnel to shut down
Units 1 and 2 of the Cook Plant. On September 19, 1997, the NRC
issued a Confirmatory Action Letter requiring the Company to
address the issues identified in the letter. The Company is
working with the NRC to resolve these issues and other issues
related to restart of the units. Certain issued identified in the
letter have been addressed. At this time management is unable to
determine when the units will be returned to service. If the units
are not returned to service in a reasonable period of time, it
could have an adverse impact on results of operations, cash flows
and possibly financial condition.
Environmental Concerns
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
Over the years AEP has spent over a billion dollars to equip our
facilities with the latest cost effective clean air and water
technologies and to research possible new technologies. We are
also proud of our award winning efforts to reclaim our mining
properties. We intend to continue in a leadership role fostering
economically prudent efforts to protect and preserve the
environment.
Hazardous Material
By-products from the generation of electricity include
materials such as ash, slag, sludge, low-level radioactive waste
and SNF. Coal combustion by-products, which constitute the
overwhelming percentage of these materials, are typically disposed
of or treated in captive disposal facilities or are beneficially
utilized. In addition, our generating plants and transmission and
distribution facilities have used asbestos, PCBs and other
hazardous and nonhazardous materials. We are currently incurring
costs to safely dispose of such substances. Additional costs could
be incurred to comply with new laws and regulations if enacted.
CERCLA or Superfund addresses clean-up of hazardous substances
at disposal sites and authorized the Federal EPA to administer the
clean-up programs. As of year-end 1997, we are involved in
litigation with respect to five sites overseen by the Federal EPA
and have been named by the Federal EPA as PRPs for seven other
sites. There are seven additional sites for which AEP companies
have received information requests which could lead to PRP
designation. Also, an AEP subsidiary has received an information
request with respect to one site administered by state authorities.
Our liability has been resolved for a number of sites with no
significant effect on results of operations. In those instances
where we have been named a PRP or defendant, our disposal or
recycling activity was in accordance with the then-applicable laws
and regulations. Unfortunately, CERCLA does not recognize
compliance as a defense, but imposes strict liability on parties
who fall within its broad statutory categories.
While the potential liability for each Superfund site must be
evaluated separately, several general statements can be made
regarding our potential future liability. Disposal at a particular
site by AEP is often unsubstantiated; the quantity of material we
disposed of at a site was generally small; and the nature of the
material we generally disposed of was nonhazardous. Typically, we
are one of many parties named as PRPs for a site and, although
liability is joint and several, generally some of the other parties
are financially sound enterprises. Therefore, our present
estimates do not anticipate material cleanup costs for identified
sites for which we have been declared PRPs. However, if for
reasons not currently identified significant cleanup costs are
attributed to AEP in the future, results of operations, cash flows
and possibly financial condition would be adversely affected unless
the costs can be recovered from customers.
Federal EPA Actions
Federal EPA is required by the CAAA to issue rules to implement
the law. In December 1996 Federal EPA issued final rules governing
NOx emissions that must be met after January 1, 2000 (Phase II of
the CAAA). The final rules will require substantial reductions in
NOx emissions from certain types of boilers including those in
AEP's power plants. On February 13, 1998, the United States Court
of Appeals for the District of Columbia Circuit, in an appeal in
which the AEP System operating companies participated, upheld the
emission limitations. In addition in November 1997 the Federal EPA
published a proposed rulemaking requiring the revision of state
implementation plans in 22 eastern states, including those states
in which the operating companies of the AEP System have coal-fired
generating plants. The proposed rule will require reductions in
NOx emissions from utility sources of approximately 85% below 1990
levels and entail very substantial capital and operating
expenditures by AEP System operating companies. Pollution controls
to meet the proposed revised NOx emission limits would have to be
in place by 2002. Eight northeast states have petitioned Federal
EPA for the imposition of additional NOx controls for upwind
industrial and utility sources. The matter is being litigated.
The costs to comply with the emission reductions required by the
Federal EPA's actions are expected to be substantial and would have
a material adverse impact on future results of operations, cash flows
and possibly financial condition if the resultant costs are not
recovered from customers.
In 1997 the Federal EPA published a revised ambient air quality
standard for ozone and established a new ambient air quality
standard for fine particulate matter. These standards are expected
to result in redesignation of a number of areas of the country
currently in compliance with the existing standard to nonattainment
status which could ultimately dictate more stringent emission
restrictions for AEP generating units. Under the new rules the
states must first determine whether the standards are being
achieved. The states then have three years to submit a compliance
plan and up to ten years after designation to come into compliance
with the new standards. The compliance deadline could be as late
as 2010 for the ozone standard and 2012-2015 for the fine
particulate standard. Although we are reviewing the impact of the
new rules, we are unable to estimate compliance costs without
knowledge of the reductions that will be necessary to meet the new
standards. If such reductions are significant and the Company must
bear a significant portion of the cost of compliance in a region
that is in violation of the revised standards, it would have a
material adverse effect on results of operations, cash flows and
possibly financial condition unless such costs are recovered from
customers.
At the global climate conference in Kyoto, Japan in December
1997 more than 160 countries, including the United States,
negotiated a treaty limiting emissions of greenhouse gases, chiefly
carbon dioxide, which may eventually contribute to global warming.
Although there is no clear scientific evidence that carbon dioxide
contributes to global warming and damages the environment, the
treaty, which requires Congressional approval, calls for a seven
percent reduction below the emission levels of greenhouse gases in
1990. We intend to work with Congress to insure that science and
reason are introduced to the debate. If approved by Congress the
costs to comply with the emission reductions required by the Kyoto
treaty is expected to be substantial and would have a material
adverse impact on results of operations, cash flows and possibly
financial condition if not recovered from customers.
Results of Operations
Net Income Declines Due to Extraordinary Loss
Net income decreased 13% to $511 million primarily due to an
extraordinary loss of $109 million from the UK's one-time windfall
tax which was based on a retroactive revaluation of the original
privatization price of certain privatized utilities, including
Yorkshire. Income before the extraordinary loss increased 6% in
1997 to $620 million or $3.28 per share from $587 million or $3.14
per share in 1996. The increase is primarily attributable to
increased transmission service sales, reduced preferred stock
dividends due to a redemption program and an increase in
nonoperating income from the April 1997 investment in Yorkshire
exclusive of the extraordinary loss.
In 1996 net income increased 11% to $587 million or $3.14 per
share from $530 million or $2.85 per share in 1995. The increase
was mainly attributable to increased sales of energy and services
and reduced interest charges and preferred stock dividends. Sales
increased due to increased transmission and other services provided
to power marketers and utilities and increased energy sales to
non-affiliated utilities and industrial customers. The reduction
in interest and preferred stock dividends resulted from the
Company's refinancing program. Also contributing to the
improvement in net income in 1996 were severance pay charges
recorded in 1995 in connection with the restructuring of management
and operations and gains recorded in 1996 from emission allowance
transactions.
Revenues and Sales Increase
Operating revenues increased 5% in 1997 and 3% in 1996.
Increased wholesale energy sales and transmission and coal
conversion service revenues were the primary reasons for the
increases in both years. The change in revenues can be analyzed as
follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1997 1996
Amount % Amount %
Retail:
Price Variance $(44.0) $ (42.9)
Volume Variance 2.4 63.7
Fuel Cost Recoveries 27.3 15.0
(14.3) (0.3) 35.8 0.7
Wholesale:
Price Variance 9.6 (202.0)
Volume Variance 269.7 317.3
Fuel Cost Recoveries 8.3 (3.6)
287.6 36.3 111.7 16.4
Other Operating Revenues 38.8 31.4
Total $312.1 5.3 $ 178.9 3.2
The slight decrease in retail revenues in 1997 was largely due
to a decline in higher priced sales to weather-sensitive
residential customers reflecting mild weather. The decline in
residential sales was completely offset by an increase in lower
priced sales to industrial customers, reflecting increased usage
which resulted in a small increase in total retail energy sales.
The negative price variance resulted from the shift from higher
priced residential sales to lower priced industrial sales.
In 1997 wholesale revenues and sales increased significantly
primarily due to new power marketing transactions which began in
July 1997 when AEP commenced a power marketing business. The new
power marketing transactions involve the substantial purchase and
sale of electricity outside of the AEP transmission system. An
increase in coal conversion service sales also contributed to the
significant increase in wholesale sales and revenues. These sales
are for the generation of electricity from the coal of the
purchaser.
An increase of $33 million in transmission service revenues
produced the increase in other operating revenues in 1997.
Transmission service revenues are for the transmission of other
companies' power through AEP's extensive transmission system.
These revenues have increased significantly since the issuance of
the FERC's open access transmission rules in 1996.
In 1996 retail revenues increased slightly due to growth in the
number of customers and the addition of a major new industrial
customer in December 1995. Revenues from higher priced sales to
residential customers, the most weather-sensitive customer class,
were flat, increasing less than one percent, as the effect of cold
winter weather in early 1996 was offset by mild summer and December
temperatures. Revenues from lower priced commercial and industrial
customers increased 1% reflecting growth in the number of
customers. The increase in lower priced commercial and industrial
sales accounted for the negative price variance in 1996.
Wholesale revenues increased 16% in 1996 reflecting a 46%
increase in wholesale sales attributable largely to transactions
with power marketers and other utilities. During 1996 the Company
began providing coal conversion services resulting in 6.8 billion
kilowatthours of electricity generated for power marketers and
certain other utilities from their coal under a new FERC-approved
interruptible, contingent sales tariff. These sales have lower
prices because there is no associated fuel cost. As a result the
average price per kilowatthour was significantly less in 1996 than
in 1995 producing a negative price variance. Also contributing to
the increased wholesale sales was a long-term contract with an
unaffiliated utility to supply 205 MW of energy for 15 years
beginning January 1, 1996.
An increased level of activity in the wholesale energy markets,
due to FERC's open access rulemaking and AEP's aggressive efforts
to provide flexible and competitively priced transmission services
led to an increase in transmission service revenues in 1996. As a
result transmission service revenues, which are recorded in other
operating revenues, increased by approximately $24 million.
The level of wholesale sales tends to fluctuate due to the
highly competitive nature of the short-term energy market and other
factors, such as affiliated and unaffiliated generating plant
availability, the weather and the economy. The FERC rules which
introduce a greater degree of competition into the wholesale energy
market have had the effect of increasing short-term wholesale sales
and transmission service revenues. The Company's sales and in turn
its results of operations were impacted in 1997 and 1996 by the
quantities of energy and services sold to wholesale customers.
Future results of operations will be affected by the quantity and
price of wholesale transactions which often depend on the level of
competition, the weather and power plant availability, both
affiliated and non-affiliated, factors the Company does not
control. However, we work to take advantage of these factors when
they are favorable.
Operating Expenses Increase
Operating expenses increased 7% in 1997 and 3% in 1996.
Increased purchased power expense, mainly from the Company's new
power marketing business, was the primary reason for the 1997
increase. New marketing, customer services and software costs to
prepare for competition also contributed to the increase. The
primary items accounting for the increase in 1996 were increased
fuel costs, federal income taxes and expenditures for marketing,
information systems and other items necessary to prepare for the
transition to competition. Changes in the components of operating
expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1997 1996
Amount % Amount %
Fuel $ 26.4 1.6 $ 63.5 4.1
Purchased Power 330.2 383.5 (2.3) (2.6)
Other Operation 17.3 1.4 25.9 2.2
Maintenance (19.6) (3.9) (39.0) (7.2)
Depreciation and Amortization (9.7) (1.6) 7.8 1.3
Taxes Other Than Federal
Income Taxes (8.0) (1.6) 9.4 1.9
Federal Income Taxes (0.9) (0.3) 70.2 25.8
Total $335.7 6.9 $135.5 2.9
Fuel expense increased in 1997 primarily due to an increase in
the average cost of fuel consumed reflecting the reduced
availability of lower cost nuclear generation in 1997 due to the
unplanned shutdown and maintenance outage of both nuclear units
which began on September 10 and continued through year-end. The
increase in fuel expense in 1996 was primarily due to an increase
in generation to meet the increase in industrial and wholesale
customer demand. The effect of increased generation was partially
offset by reduced average fossil fuel costs, resulting from
increased usage of lower cost spot market coal, and lower cost
nuclear fuel.
The significant increase in purchased power expense in 1997 was
primarily due to purchases of electricity for the new power
marketing business. These purchases were made to cover sales made
to non-affiliates by the new power marketers.
In 1997 restructuring savings in other operation expense were
more than offset by additional expenses for marketing, customer
service and software costs to prepare for the service demands of
competition.
Maintenance expense decreased in 1996 due to the deferral of
previously expensed storm damage costs commensurate with their
recovery over 5-years and reduced nuclear plant maintenance expense
due to workforce reductions and the reduction of contract labor at
the Cook Nuclear Plant.
The increase in federal income tax expense attributable to
operations in 1996 was primarily due to an increase in pre-tax
operating income and changes in certain book/tax differences
accounted for on a flow-through basis and certain permanent
differences.
Nonoperating Income
The increase in nonoperating income in 1997 was mainly due to
income from non-regulated operations. The Company's share of
earnings from its April 1997 investment in Yorkshire was $34
million which includes $10 million of nonrecurring tax benefits
related to a reduction of the UK corporate income tax rate from 33%
to 31% effective April 1,1997. The utilization of foreign tax
credits also contributed to the increase in nonoperating income.
Nonoperating income decreased in 1996 due to the cost of the AEP
branding program and the cost of efforts to develop and make
investment in new non-regulated business ventures.
Interest Charges and Preferred Stock Dividend Requirements
In 1997 interest charges on both long-term and short-term debt
increased reflecting additional borrowing primarily to fund the
Company's non-regulated operations including the investment in
Yorkshire. Preferred stock dividend requirements of the
subsidiaries decreased in 1997 due to the reacquisition of over 4
million shares of cumulative preferred stock.
The decrease in interest charges and preferred stock dividend
requirements in 1996 was mainly due to continued refinancing
programs of the Company's subsidiaries. The refinancings reduced
the average interest rate and the amount of long-term debt and
preferred stock outstanding. The cost of short-term borrowings in
1996 increased slightly reflecting an increased average balance of
short-term debt outstanding.
Financial Condition
In 1997 AEP maintained its strong financial condition and
performance in shareholder value. The year-end closing stock price
of $51-5/8 was 25.5% higher than the prior year and 57% greater
than the 1994 closing price. The Company paid a quarterly dividend
in 1997 of 60 cents a share maintaining the annual dividend rate at
$2.40 per share. The 1997 payout ratio before extraordinary loss
at 73% was 3% better than 1996's and 15% better than 1994's. It
has been a management objective to reduce the payout ratio through
efforts to increase earnings in order to enhance AEP's ability to
invest in new business ventures that can complement our core
competencies and improve shareholder value. AEP's three-year
total shareholder return ranked fourth among the companies in the
S&P Electric Utility Index. This marked the fourth straight year
in the top quartile of the Index. Management's goal is to maintain
our position in the top quartile of the S&P Electric Utility Index
for three-year total shareholder return.
Capital Investments
The total consideration paid in 1997 by a joint venture of AEP
and an unaffiliated company to acquire Yorkshire was approximately
$2.4 billion which was financed by a combination of equity and non-recourse
debt. AEP initially funded its 50% equity investment in
the joint venture with $50 million in cash, a $300 million
adjustable rate term loan under a long-term revolving credit
agreement and $10 million of short-term debt. For more information
see Note 7 of the Notes to Consolidated Financial Statements. Also
the Company's 70% interest in the construction of two 125 MW units
in China will require approximately $110 million of investment.
AEP's construction expenditures are expected to be $2.4 billion
over the next three years which includes the Cook Plant's Unit 1
steam generator replacement, the China project and the cost of
transmission and distribution projects for the improvement of and
addition to electric energy delivery facilities. Approximately 90%
of domestic construction expenditures, estimated to be $2.3 billion
for the next three years, will be financed with internally
generated funds.
Capital Resources - Structure and Liquidity
AEP achieved a year-end ratio of common equity to total
capitalization including amounts due within one year of 45.5% for
1997, compared with 45.3% for 1996 and 43.1% for 1995. The
Company's goal is to maintain the common equity ratio at a
level of at least 40 percent. During 1997 the Company
and its subsidiaries continued redefining and improving their debt
to equity position. The Company's regulated subsidiaries redeemed
4,258,947 shares of cumulative preferred stock with rates ranging
from 4.08% to 7.875% at a total cost of $433 million. The
subsidiaries used short-term debt and junior subordinated
deferrable interest debentures to pay for the preferred stock
tendered and to benefit from the tax deductibility of interest.
The Company and its subsidiaries issued $882 million principal
amount of long-term obligations in 1997 at interest rates ranging
from 5.9% to 8.0%. The companies continued to reduce financing
costs by retiring higher-cost bonds and restructuring the long-term
debt from senior secured/first mortgage bonds to senior unsecured
debt and junior debentures. The principal amount of long-term debt
retirements, including maturities, totaled $343 million with
interest rates ranging from 6.5% to 9.35%. Our operating
subsidiaries senior secured debt/first mortgage bond ratings, which
were reaffirmed and improved in 1997, are listed in the following
table:
Company Moody's S&P Fitch D & P
APCo A3 A A A
CSPCo A3 A- A- A
I&M Baa1 A- BBB+ N/A
KPCo Baa1 A BBB+ N/A
OPCo A3 A- A- A
N/A = Not applicable
The operating subsidiaries generally issue short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. They periodically reduce their
outstanding short-term debt through issuances of long-term debt and
additional capital contributions by the parent company. The
companies formed to pursue non-regulated business opportunities are
using short-term debt. Short-term debt increased $235 million from
the prior year-end balance and decreased by $45 million in 1996.
At December 31, 1997, AEP Co., Inc. (the parent company) and its
subsidiaries had unused short-term lines of credit of $442 million,
and several of AEP's subsidiaries engaged in non-regulated
investments and energy businesses had available $330 million under
a $600 million revolving credit agreement which expires in 1999.
The sources of funds available to AEP are dividends from its
subsidiaries, short-term and long-term borrowings and, when
necessary, proceeds from the issuance of common stock. AEP issued
1,755,000 shares in 1997, 1,600,000 shares in 1996 and 1,400,000
shares in 1995 of common stock through a Dividend Reinvestment
Program and the Employee Savings Plan raising $77 million, $65
million and $49 million, respectively.
The following debt and preferred stock coverages of the
principal operating subsidiaries remained strong in 1997:
Coverages at December 31, 1997
Preferred
Mortgage Stock
APCo 3.72 1.92
CSPCo 4.95 N/A
I&M 7.57 2.88
KPCo 4.23 N/A
OPCo 9.74 3.67
N/A = Not Applicable
Unless the subsidiaries meet certain earnings or coverage
tests, they cannot issue additional mortgage bonds or preferred
stock. In order to issue mortgage bonds (without refunding
existing debt), each subsidiary must have pre-tax earnings equal to
at least two times the annual interest charges on mortgage bonds
after giving effect to the issuance of the new debt. Generally,
issuance of additional preferred stock requires after-tax gross
income at least equal to one and one-half times annual interest and
preferred stock dividend requirements after giving effect to the
issuance of the new preferred stock. As the above chart indicates,
the subsidiaries presently exceed these minimum coverage
requirements.
Merger
In December 1997 AEP and CSW announced that their boards of
directors approved a definitive merger agreement for a tax-free,
stock-for-stock business combination transaction which if
consummated would bring AEP's total market capitalization to
approximately $28 billion. The combination is expected to be
accounted for as a pooling of interests. Under the agreement, each
common share of CSW will be converted to 0.6 shares of AEP. Based
on the number of CSW common shares outstanding at December 31,
1997, AEP will issue approximately 127 million shares to CSW common
stockholders (valued at $6.6 billion based on the closing price on
the last trading day prior to the announcement of the merger).
Under the merger agreement, there will be no changes with respect
to the public debt issues or the outstanding preferred stock of
AEP, CSW or their subsidiaries. The merger is conditioned, among
other things, upon the approval of each company's shareholders and
certain state and federal regulatory agencies. The companies
anticipate that the required regulatory approvals can be obtained
in 12 to 18 months. AEP is requesting regulatory and shareholder
approval to increase the number of authorized shares from
300,000,000 to 600,000,000 in connection with the merger.
Market Risks
The Company as a major power producer and a trader of
electricity and gas has certain financial market risks inherent in
its routine business activities. The trading of electricity and
gas and related future contracts exposes the Company to commodity
price fluctuations. Market risk represents the risk of loss that
may impact the Company's consolidated financial position, results
of operations or cash flows due to adverse changes in market prices
and rates. As trading activity increases and the market for power
evolves this risk will become much greater. Various policies and
procedures have been established to manage market risks exposures
including the limited usage of energy related derivatives. In its
regular business activities, certain trading positions of the
Company for electric and gas creates exposure to price volatility
for those products. These commodities are subject to unpredictable
price fluctuations due to changing economic and weather conditions.
During 1997 the Company initiated a power and gas marketing
operation that manages the Company's exposure to future price
movements using forwards, futures and options. At December 31,
1997, the exposure for financial derivatives in these marketing
activities were not material to the Company's consolidated results
of operations, financial position or cash flows.
Investment in two foreign currency denominated joint ventures
also exposes the Company to currency translation rate risk. At
December 31, 1997, the Company's exposure to changes in foreign
currency exchange rates related to projects in the UK and China is
not material to its consolidated financial position, results of
operations or cash flows. The Company does not presently utilize
derivatives to manage its exposures to foreign currency exchange
rate movements.
The Company is exposed to changes in interest rates primarily
due to short- and long-term borrowings to fund its business
operations. The debt portfolio has both fixed and variable
interest rates, terms from one day to thirty years and an average
duration of eight years at December 31, 1997.
The Company measures interest rate market risk exposure
utilizing a VaR model. The model is based on the Monte Carlo
method of simulated price movements with a 95% confidence level and
a one year holding period. The volatilities and correlations were
based on three years of monthly prices. The risk of potential loss
in fair value attributable to the Company's exposure to interest
rates, primarily related to long-term debt with fixed interest
rates, was $501 million at December 31, 1997. A near term change
in interest rates would not materially affect the consolidated
financial position or results of operations of the Company. The
Company is not currently utilizing derivatives to manage its
exposure to interest rate fluctuations.
The Company has investments in debt and equity securities which
are held in trust funds to decommission its nuclear plant.
Approximately 85% of the trust fund value is invested in tax exempt
and taxable bonds, short-term debt instruments or cash. The trust
investments and their fair value are discussed in Note 9 of the
Notes to Consolidated Financial Statements. Instruments in the
trust funds have not been included in the market risk calculation
for interest rates as these instruments are marked-to-market and
changes in market value are reflected in a corresponding
decommissioning liability. Any differences between trust fund and
ultimate liability are recoverable from ratepayers.
Inflation affects AEP's cost of replacing utility plant and the
cost of operating and maintaining its plant. The rate-making
process limits our recovery to the historical cost of assets
resulting in economic losses when the effects of inflation are not
recovered from customers on a timely basis. However, economic
gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
Other Matters
Corporate Owned Life Insurance
In connection with the audit of AEP's consolidated federal
income tax returns the IRS agents sought a ruling from the IRS
National Office that certain interest deductions relating to a COLI
program should not be allowed. The Company established the COLI
program in 1990 as a part of its strategy to fund and reduce the
cost of medical benefits for retired employees. AEP filed a brief
with the IRS National Office refuting the agents' position. No
adjustments have been proposed by the IRS. However, should a full
disallowance of COLI interest deductions be proposed it would, if
sustained, reduce earnings by approximately $286 million (including
interest). AEP believes it has meritorious defenses and will
vigorously contest any proposed adjustments. No provisions for
this amount have been recorded. In the event the Company is
unsuccessful it could have a material adverse impact on results of
operations and cash flows.
Computer Software - Year 2000 Compliance
Many existing computer hardware and software programs will not
properly recognize calendar dates beginning in the year 2000.
Unless corrected, this "Year 2000" problem may cause computer
malfunctions, such as system shutdowns or incorrect calculations
and system output. The Company is addressing the problem
internally by modifying or replacing its computer hardware and
software programs to mitigate its risk, minimize technical
failures, and repair such failures if they occur. The problem is
also being addressed externally with entities that interact
electronically with the Company, including but not limited to,
suppliers, service providers, government agencies, customers,
creditors and financial service organizations. However, due to the
complexity of the problem and the interdependent nature of computer
systems, if the Company's corrective actions, and/or the actions of
other interdependent entities, fail for critical applications, the
Company may be adversely impacted in the year 2000. Although
significant, the cost of correcting the "Year 2000" problem is not
expected to have a material impact on results of operations, cash
flows or financial condition.
New Accounting Standards
In June 1997 the FASB issued SFAS No. 130 "Reporting
Comprehensive Income" and SFAS No. 131 "Disclosures About Segments
of an Enterprise and Related Information." SFAS No. 130 establishes
the standards for reporting and displaying components of
"comprehensive income," which is the total of net income and all
other changes in equity except those resulting from investments by
shareholders and dispositions to shareholders. SFAS No. 131
initiates standards for reporting information about operating
segments in annual and interim financial statements as well as
related disclosures about products and services, geographic areas
and major customers. AEP's adoption of these new reporting
standards in 1998 is not expected to have a material adverse effect
on the results of operations, cash flows and/or financial condition.
Litigation
AEP is involved in a number of legal proceedings and claims.
While we are unable to predict the outcome of such litigation, it
is not expected that the ultimate resolution of these matters will
have a material adverse effect on the results of operations, cash
flows and/or financial condition.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
Year Ended December 31,
1997 1996 1995
OPERATING REVENUES $6,161,368 $5,849,234 $5,670,330
OPERATING EXPENSES:
Fuel 1,627,066 1,600,659 1,537,135
Purchased Power 416,266 86,095 88,396
Other Operation 1,227,368 1,210,027 1,184,158
Maintenance 483,268 502,841 541,825
Depreciation and Amortization 591,071 600,851 593,019
Taxes Other Than Federal Income Taxes 490,595 498,567 489,223
Federal Income Taxes 341,280 342,222 272,027
TOTAL OPERATING EXPENSES 5,176,914 4,841,262 4,705,783
OPERATING INCOME 984,454 1,007,972 964,547
NONOPERATING INCOME (net) 59,572 2,212 20,204
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 1,044,026 1,010,184 984,751
INTEREST CHARGES 405,815 381,328 400,077
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 17,831 41,426 54,771
INCOME BEFORE EXTRAORDINARY ITEM 620,380 587,430 529,903
EXTRAORDINARY LOSS - UK WINDFALL TAX (109,419) - -
NET INCOME $ 510,961 $ 587,430 $ 529,903
AVERAGE NUMBER OF SHARES OUTSTANDING 189,039 187,321 185,847
EARNINGS PER SHARE:
Before Extraordinary Item $3.28 $3.14 $2.85
Extraordinary Loss (0.58) - -
Net Income $2.70 $3.14 $2.85
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
Year Ended December 31,
1997 1996 1995
RETAINED EARNINGS JANUARY 1 $1,547,746 $1,409,645 $1,325,581
NET INCOME 510,961 587,430 529,903
DEDUCTIONS:
Cash Dividends Declared 453,453 449,353 445,831
Other 237 (24) 8
RETAINED EARNINGS DECEMBER 31 $1,605,017 $1,547,746 $1,409,645
See Notes to Consolidated Financial Statements.
/TABLE
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(in thousands - except share data)
December 31,
1997 1996
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 9,493,158 $ 9,341,849
Transmission 3,501,580 3,380,258
Distribution 4,654,234 4,402,449
General (including mining assets and nuclear fuel) 1,604,671 1,491,781
Construction Work in Progress 342,842 353,832
Total Electric Utility Plant 19,596,485 18,970,169
Accumulated Depreciation and Amortization 7,963,636 7,549,798
NET ELECTRIC UTILITY PLANT 11,632,849 11,420,371
OTHER PROPERTY AND INVESTMENTS 1,358,810 892,674
CURRENT ASSETS:
Cash and Cash Equivalents 91,481 57,539
Accounts Receivable:
Customers (less allowance for uncollectible
accounts of $6,760 in 1997 and $3,692 in 1996) 552,443 415,413
Miscellaneous 115,075 115,919
Fuel - at average cost 224,967 235,257
Materials and Supplies - at average cost 263,613 251,896
Accrued Utility Revenues 189,191 174,966
Prepayments and Other 81,366 103,891
TOTAL CURRENT ASSETS 1,518,136 1,354,881
REGULATORY ASSETS 1,817,540 1,889,482
DEFERRED CHARGES 288,011 325,580
TOTAL $16,615,346 $15,882,988
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31,
1997 1996
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock-Par Value $6.50:
1997 1996
Shares Authorized. .300,000,000 300,000,000
Shares Issued. . . .198,989,981 197,234,992
(8,999,992 shares were held in treasury) $ 1,293,435 $ 1,282,027
Paid-in Capital 1,778,782 1,715,554
Retained Earnings 1,605,017 1,547,746
Total Common Shareholders' Equity 4,677,234 4,545,327
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 46,724 90,323
Subject to Mandatory Redemption 127,605 509,900
Long-term Debt* 5,129,463 4,796,768
TOTAL CAPITALIZATION 9,981,026 9,942,318
OTHER NONCURRENT LIABILITIES 1,246,537 1,002,208
CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year* 294,454 86,942
Short-term Debt 555,075 319,695
Accounts Payable 353,256 206,227
Taxes Accrued 380,771 414,173
Interest Accrued 76,361 75,124
Obligations Under Capital Leases 101,089 89,553
Other 322,687 304,323
TOTAL CURRENT LIABILITIES 2,083,693 1,496,037
DEFERRED INCOME TAXES 2,560,921 2,643,143
DEFERRED INVESTMENT TAX CREDITS 376,250 401,491
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 231,320 240,598
DEFERRED CREDITS 135,599 157,193
COMMITMENTS AND CONTINGENCIES (Note 4 )
TOTAL $16,615,346 $15,882,988
*See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
1997 1996 1995
OPERATING ACTIVITIES:
Net Income $ 510,961 $ 587,430 $ 529,903
Adjustments for Noncash Items:
Depreciation and Amortization 608,217 590,657 578,003
Deferred Federal Income Taxes (6,549) (21,478) 11,916
Deferred Investment Tax Credits (25,241) (25,808) (25,819)
Amortization of Operating Expenses
and Carrying Charges (net) 12,001 55,458 53,479
Extraordinary Item - UK Windfall Tax 109,419 - -
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (136,186) (39,049) (71,804)
Fuel, Materials and Supplies (1,427) 35,831 457
Accrued Utility Revenues (14,225) 32,953 (40,433)
Accounts Payable 147,029 (13,915) (31,044)
Taxes Accrued (33,402) (6,019) 37,515
Other (net) 27,325 41,002 14,437
Net Cash Flows From Operating
Activities 1,197,922 1,237,062 1,056,610
INVESTING ACTIVITIES:
Construction Expenditures (760,394) (577,691) (605,974)
Investment in Yorkshire (363,436) - -
Proceeds from Sale of Property and Other 2,142 12,283 20,567
Net Cash Flows Used For
Investing Activities (1,121,688) (565,408) (585,407)
FINANCING ACTIVITIES:
Issuance of Common Stock 76,745 65,461 48,707
Issuance of Long-term Debt 880,522 407,291 523,476
Retirement of Cumulative Preferred Stock (433,329) (70,761) (158,839)
Retirement of Long-term Debt (348,157) (601,278) (469,767)
Change in Short-term Debt (net) 235,380 (45,430) 48,140
Dividends Paid on Common Stock (453,453) (449,353) (445,831)
Net Cash Flows Used For
Financing Activities (42,292) (694,070) (454,114)
Net Increase (Decrease) in Cash and
Cash Equivalents 33,942 (22,416) 17,089
Cash and Cash Equivalents January 1 57,539 79,955 62,866
Cash and Cash Equivalents December 31 $ 91,481 $ 57,539 $ 79,955
See Notes to Consolidated Financial Statements.
/TABLE
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
Organization - AEP is one of the U.S.'s largest investor-owned public
utility holding companies engaged in the generation, purchase,
transmission and distribution of electric power to nearly 3 million
retail customers in its seven state service territory which covers
portions of Ohio, Michigan, Indiana, Kentucky, West Virginia,
Virginia and Tennessee. Electric power is also supplied at
wholesale to neighboring utility systems and power marketers. AEP
has holdings in the United States, the UK and China.
The organization of the AEP System consists of AEP Company, Inc.,
the parent holding company; seven electric utility operating
companies in the U.S. (domestic utility subsidiaries); a domestic
generating subsidiary, AEPGEN; a service company, AEPSC; AEPR which
pursues energy-related domestic and international investment
opportunities and projects; AEPES which markets and trades energy
commodities; three active coal-mining companies and a group of
subsidiaries that provide power engineering, consulting and
management services around the world to complement utility
activities.
The following domestic utility subsidiaries pool their generating
and transmission facilities and operate them as an integrated
system: APCo, CSPCo, I&M, KPCo and OPCo. The remaining two
domestic utility subsidiaries, KGPCo and WPCo are distribution
companies that purchase power from APCo and OPCo, respectively.
AEPSC provides management and professional services to the AEP
System. The active coal-mining companies are wholly-owned by OPCo
and sell most of their production to OPCo. AEPGEN has a 50%
interest in the Rockport Plant which is comprised of two of the AEP
System's six 1,300 mw generating units. AEPR has investments and
projects that include: a 50% interest in Yorkshire, an electric
distribution company in the UK (see Note 7); a 70% interest in a
project to build two 125 mw coal-fired generating units in China.
AEPES currently markets and trades natural gas. The non-regulated
subsidiaries that complement utility activities are engaged in
providing non-regulated energy and communication services and are
seeking and considering new business opportunities domestically and
internationally that will permit AEP to utilize its expertise and
core competencies.
The AEP System's operations are divided into major business units
which are managed centrally by AEPSC. Although the seven domestic
utility subsidiaries and AEPSC are separate legal entities they
operate as American Electric Power. There has been no change to
the legal names of these companies.
Rate Regulation - The AEP System is subject to regulation by the
SEC under the 1935 Act. The rates charged by the domestic utility
subsidiaries are approved by the FERC or the state utility
commissions as applicable. The FERC regulates wholesale rates and
the state commissions regulate retail rates.
Principles of Consolidation - The consolidated financial statements
include AEP Co., Inc. and its wholly-owned and majority-owned
subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Yorkshire is accounted for using the equity method.
Basis of Accounting - As the owner of cost-based rate-regulated
electric public utility companies, AEP Co., Inc.'s consolidated
financial statements reflect the actions of regulators that result
in the recognition of revenues and expenses in different time
periods than enterprises that are not rate regulated. In
accordance with SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation," regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) are recorded to reflect
the economic effects of regulation and to match expenses with
regulated revenues.
Use of Estimates - The preparation of these financial statements in
conformity with generally accepted accounting principles requires
in certain instances the use of estimates. Actual results could
differ from those estimates.
Utility Plant - Electric utility plant is stated at original cost
and is generally subject to first mortgage liens. Additions, major
replacements and betterments are added to the plant accounts.
Retirements from the plant accounts and associated removal costs,
net of salvage, are deducted from accumulated depreciation. The
costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
AFUDC - AFUDC is a noncash nonoperating income item that is
recovered over the service life of utility plant through
depreciation and represents the estimated cost of borrowed and
equity funds used to finance construction projects. The average
rates used to accrue AFUDC were 6%, 6.09%, and 6.91% in 1997, 1996
and 1995, respectively.
Depreciation, Depletion and Amortization - Depreciation is provided
on a straight-line basis over the estimated useful lives of
property other than coal-mining property and is calculated largely
through the use of composite rates by functional class as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.7% to 3.2%
Transmission 1.7% to 2.7%
Distribution 3.3% to 4.2%
General 2.5% to 3.8%
The utility subsidiaries presently recover amounts to be used for
demolition and removal of non-nuclear plant through depreciation
charges included in rates. Depreciation, depletion and
amortization of coal-mining assets is provided over each asset's
estimated useful life, ranging up to 30 years, and is calculated
using the straight-line method for mining structures and equipment.
The units-of-production method is used to amortize coal rights and
mine development costs based on estimated recoverable tonnages at
a current average rate of $1.91 per ton. These costs are included
in the cost of coal charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include
temporary cash investments with original maturities of three months
or less.
Foreign Currency Translation - The financial statements of
subsidiaries outside the United States are measured using the local
currency as the functional currency. Assets and liabilities are
translated to U.S. dollars at year-end rates of exchange and
revenues and expenses are translated at monthly average exchange
rates throughout the year. Translation adjustments are accumulated
as a separate component of shareholders' equity. The accumulated
total at December 31, 1997 is not material. Currency transaction
gains and losses are recorded in income.
Sale of Receivables - Under an agreement that was terminated in
January 1997, CSPCo sold $50 million of undivided interests in
designated pools of accounts receivable and accrued utility
revenues with limited recourse. As collections reduced previously
sold pools, interests in new pools were sold. At December 31,
1996, $50 million remained to be collected and remitted to the
buyer.
Operating Revenues and Fuel Costs - Revenues include the accrual of
electricity consumed but unbilled at month-end as well as billed
revenues. Fuel costs are matched with revenues in accordance with
rate commission orders. Generally in the retail jurisdictions,
changes in fuel costs are deferred or revenues accrued until
approved by the regulatory commission for billing or refund to
customers in later months. Wholesale jurisdictional fuel cost
changes are expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs - Incremental
operation and maintenance costs associated with refueling outages
at I&M's Cook Plant are deferred and amortized over the period
(generally eighteen months) beginning with the commencement of an
outage and ending with the beginning of the next outage.
Income Taxes - The Company follows the liability method of
accounting for income taxes as prescribed by SFAS No. 109,
"Accounting for Income Taxes." Under the liability method,
deferred income taxes are provided for all temporary differences
between the book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through
method of accounting for temporary differences is reflected in
rates, deferred income taxes are recorded with related regulatory
assets and liabilities in accordance with SFAS No. 71.
Investment Tax Credits - Investment tax credits have been accounted
for under the flow-through method except where regulatory
commissions have reflected investment tax credits in the rate-making process
on a deferral basis. Deferred investment tax
credits are being amortized over the life of the related plant
investment.
Debt and Preferred Stock - Gains and losses on reacquisition of
debt are deferred and amortized over the remaining term of the
reacquired debt in accordance with rate-making treatment. If the
debt is refinanced, the reacquisition costs are deferred and
amortized over the term of the replacement debt commensurate with
their recovery in rates.
Discount or premium and expenses of debt issuances are amortized
over the term of the related debt, with the amortization included
in interest charges.
Redemption premiums paid to reacquire preferred stock are included
in paid-in capital and amortized to retained earnings commensurate
with their recovery in rates. The excess of par value over costs
of preferred stock reacquired is credited to paid-in capital and
amortized to retained earnings.
Other Property and Investments - Excluding decommissioning and
spent nuclear fuel disposal trust funds and the investment in
Yorkshire, other property and investments are stated at cost.
Securities held in trust funds for decommissioning nuclear
facilities and for the disposal of spent nuclear fuel are recorded
at market value in accordance with SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities." Securities in
the trust funds have been classified as available-for-sale due to
their long-term purpose. Unrealized gains and losses from
securities in these trust funds are not reported in equity but
result in adjustments to the liability account for the nuclear
decommissioning trust funds and to regulatory assets or liabilities
for the spent nuclear fuel disposal trust funds.
EPS - The adoption of SFAS No. 128 "Earnings per Share" had no
impact on the determination of Earnings per Common Share.
2. Rate Matters:
OPCo's Recovery of Fuel Costs - Under the terms of a 1992
stipulation agreement the cost of coal burned at the Gavin Plant is
subject to a 15-year predetermined price of $1.575 per million
Btu's with quarterly escalation adjustments through November 2009.
A 1995 Settlement Agreement set the fuel component of the EFC
factor at 1.465 cents per Kwh for the period June 1, 1995 through
November 30, 1998. The stipulation and settlement agreements
provide OPCo with the opportunity to recover over the term of the
stipulation agreement the Ohio jurisdictional share of OPCo's
investment in and the liabilities and future shut-down costs of its
affiliated mines as well as any fuel costs incurred above the
predetermined rate to the extent the actual cost of coal burned at
the Gavin Plant is below the predetermined prices. After full
recovery of these costs or November 2009, whichever comes first,
the price that OPCo can recover for coal from its affiliated Meigs
mine which supplies the Gavin Plant will be limited to the lower of
cost or the then-current market price. Pursuant to these
agreements OPCo has deferred for future recovery $61 million at
December 31, 1997.
Based on the estimated future cost of coal burned at Gavin Plant,
management believes that the Ohio jurisdictional portion of the
investment in and liabilities and closing costs of the affiliated
mining operations including deferred amounts will be recovered
under the terms of the predetermined price agreement. Management
intends to seek from non-Ohio jurisdictional ratepayers recovery of
the non-Ohio jurisdictional portion of the investment in and the
liabilities and closing costs of the affiliated Meigs, Muskingum
and Windsor mines. The non-Ohio jurisdictional portion of shutdown
costs for these mines which includes the investment in the mines,
leased asset buy-outs, reclamation costs and employee benefits is
estimated to be approximately $102 million after tax at December
31, 1997.
The affiliated Muskingum and Windsor mines may have to close by
January 2000 in order to comply with the Phase II requirements of
the CAAA. The Muskingum and/or Windsor mines could close prior to
January 2000 depending on the economics of continued operation
under the terms of the above Settlement Agreement. Unless future
shutdown costs and/or the cost of affiliated coal production of the
Meigs, Muskingum and Windsor mines can be recovered, results of
operations would be adversely affected.
3. Effects of Regulation and Phase-In Plans:
In accordance with SFAS No. 71 the consolidated financial
statements include assets (deferred expenses) and liabilities
(deferred income) recorded in accordance with regulatory actions to
match expenses and revenues from cost-based rates. Regulatory
assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to
reduce future cost recoveries. The Company has reviewed all the
evidence currently available and concluded that it continues to
meet the requirements to apply SFAS No. 71. In the event a portion
of the Company's business no longer met these requirements, net
regulatory assets would have to be written off for that portion of
the business and assets attributable to that portion of the business
would have to be tested for possible impairment and if required an
impairment loss recorded unless the net regulatory assets and
impairment losses are recoverable as a stranded investment.
Recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
1997 1996
(In Thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,372,926 $1,459,086
Rate Phase-in Plan Deferrals - 27,249
Unamortized Loss on Reacquired Debt 96,793 107,305
Other 347,821 295,842
Total Regulatory Assets $1,817,540 $1,889,482
Regulatory Liabilities:
Deferred Investment Tax Credits $376,250 $401,491
Other Regulatory Liabilities* 78,802 86,609
Total Regulatory Liabilities $455,052 $488,100
* Included in Deferred Credits on Consolidated Balance Sheets
The rate phase-in plan deferrals are applicable to the Zimmer Plant
and Rockport Plant Unit 1. The Zimmer Plant is a 1,300 mw coal-fired
plant which commenced commercial operation in 1991. CSPCo
owns 25.4% of the plant with the remainder owned by two
unaffiliated companies. As a result of an Ohio Supreme Court
decision, in January 1994 the PUCO approved a temporary 3.39%
surcharge effective February 1, 1994. In June 1997 the Company
completed recovery of its Zimmer Plant phase-in plan deferrals and
discontinued the 3.39% temporary rate surcharge. In 1997, 1996 and
1995 $15.4 million, $31.5 million and $28.5 million, respectively,
of net phase-in deferrals were collected through the surcharge.
The deferral balance which was completely recovered and amortized
in 1997 was $15.4 million at December 31, 1996.
The Rockport Plant consists of two 1,300 mw coal-fired units.
I&M and AEPGEN each own 50% of one unit (Rockport 1) and lease a
50% interest in the other unit (Rockport 2) from unaffiliated
lessors under an operating lease. The gain on the sale and
leaseback of Rockport 2 was deferred and is being amortized, with
related taxes, over the initial lease term which expires in 2022.
A rate phase-in plan in the Indiana and the FERC jurisdictions
provide for the recovery and straight-line amortization of deferred
Rockport Plant Unit 1 costs over ten years beginning in 1987. In
1997 the amortization and recovery of the deferred Rockport Plant
Unit 1 Phase-in Plan costs were completed. During the recovery
period net income was unaffected by the recovery of the phase in
deferrals. Amortization was $11.9 million in 1997 and $16 million
in 1996 and 1995.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial
construction commitments to support its utility operations
including the replacement of the Cook Plant Unit 1 steam
generators. Such commitments do not presently include any
expenditures for new generating capacity. Aggregate construction
expenditures for 1998-2000 are estimated to be $2.4 billion.
Long-term fuel supply contracts contain clauses for periodic
price adjustments, and most jurisdictions have fuel clause
mechanisms that provide for recovery of changes in the cost of fuel
with the regulators' review and approval. The contracts are for
various terms, the longest of which extends to the year 2014, and
contain various clauses that would release the Company from its
obligation under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,000 mw
of capacity on a long-term basis to unaffiliated utilities.
Certain contracts totaling 750 mw of capacity are unit power
agreements requiring the delivery of energy only if the unit
capacity is available. The power sales contracts expire from 1999
to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook
Plant under licenses granted by the NRC. The operation of a
nuclear facility involves special risks, potential liabilities, and
specific regulatory and safety requirements. Should a nuclear
incident occur at any nuclear power plant facility in the United
States, the resultant liability could be substantial. By agreement
I&M is partially liable together with all other electric utility
companies that own nuclear generating units for a nuclear power
plant incident. In the event nuclear losses or liabilities are
underinsured or exceed accumulated funds and recovery in rates is
not possible, results of operations, cash flows and financial
condition could be negatively affected.
Nuclear Plant Shutdown - On September 9 and 10, 1997, during a NRC
architect engineer design inspection, questions regarding the
operability of certain safety systems caused Company operations
personnel to shut down Units 1 and 2 of the Cook Plant. On
September 19, 1997, the NRC issued a Confirmatory Action Letter
requiring the Company to address the issues identified in the
letter. The Company is working with the NRC to resolve these
issues and other issues related to restart of the units. Certain
issues identified in the letter have been addressed. At this time
management is unable to determine when the units will be returned
to service. If the units are not returned to service in a
reasonable period of time, it could have an adverse impact on
results of operations, cash flows and possibly financial condition.
Nuclear Incident Liability - Public liability is limited by law to
$8.9 billion should an incident occur at any licensed reactor in
the United States. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any
nuclear plant in the United States the remainder of the liability
would be provided by a deferred premium assessment of $79.3 million
on each licensed reactor payable in annual installments of $10
million. As a result, I&M could be assessed $158.6 million per
nuclear incident payable in annual installments of $20 million.
The number of incidents for which payments could be required is not
limited.
Nuclear insurance pools and other insurance policies provide
$3.6 billion (reduced to $3.0 billion effective January 1, 1998) of
property damage, decommissioning and decontamination coverage for
the Cook Plant. Additional insurance provides coverage for extra
costs resulting from a prolonged accidental Cook Plant outage.
Some of the policies have deferred premium provisions which could
be triggered by losses in excess of the insurer's resources. The
losses could result from claims at the Cook Plant or certain other
non-affiliated nuclear units. I&M could be assessed up to $35.8
million under these policies.
SNF Disposal - Federal law provides for government responsibility
for permanent spent nuclear fuel disposal and assesses nuclear
plant owners fees for spent fuel disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being
collected from customers and remitted to the U.S. Treasury. Fees
and related interest of $181 million for fuel consumed prior to
April 7, 1983 have been recorded as long-term debt. I&M has not
paid the government the pre-April 1983 fees due to continued delays
and uncertainties related to the federal disposal program. At
December 31, 1997, funds collected from customers towards payment
of the pre-April 1983 fee and related earnings thereon approximate
the liability.
Decommissioning and Low Level Waste Accumulation Disposal -
Decommissioning costs are accrued over the service life of the Cook
Plant. The licenses to operate the two nuclear units expire in
2014 and 2017. After expiration of the licenses the plant is
expected to be decommissioned through dismantlement. The Company's
latest estimate for decommissioning and low level radioactive waste
accumulation disposal costs range from $700 million to $1,152
million in 1997 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time
spent nuclear fuel must be stored at the plant subsequent to
ceasing operations. This in turn depends on future developments in
the federal government's SNF disposal program. Continued delays in
the federal fuel disposal program can result in increased
decommissioning costs. I&M is recovering estimated decommissioning
costs in its three rate-making jurisdictions based on at least the
lower end of the range in the most recent decommissioning study at
the time of the last rate proceeding. I&M records decommissioning
costs in other operation expense and records a noncurrent liability
equal to the decommissioning cost recovered in rates; such amounts
were $28 million in 1997, $27 million in 1996 and $30 million in
1995 including $4 million of special deposits. Decommissioning
costs recovered from customers are deposited in external trusts.
Trust fund earnings increase the fund assets and the recorded
liability and decrease the amount needed to be recovered from
ratepayers. At December 31, 1997, I&M has recognized a
decommissioning liability of $381 million which is included in
other noncurrent liabilities.
Revised Air Quality Standards - On July 18, 1997, the Federal EPA
published a revised NAAQS for ozone and a new NAAQS for fine
particulate matter (less than 2.5 microns in size). The new ozone
standard is expected to result in redesignation of a number of
areas of the country that are currently in compliance with the
existing standard to nonattainment status which could ultimately
dictate more stringent emission restrictions for AEP System
generating units. New stringent emission restrictions on AEP
System generating units to achieve attainment of the fine
particulate matter standard could also be imposed. The AEP System
operating companies joined with other utilities to appeal the
revised NAAQS and filed petitions for review in August and
September 1997 in the U.S. Court of Appeals for the District of
Columbia Circuit. Management is unable to estimate compliance
costs without knowledge of the reductions that may be necessary to
meet the new standards. If such costs are significant, it could
have a material adverse effect on results of operations, cash flows
and possibly financial condition unless such costs are recovered.
Litigation - The Company is involved in a number of legal
proceedings and claims. While management is unable to predict the
ultimate outcome of litigation, it is not expected that the
resolution of these matters will have a material adverse effect on
the results of operations, cash flows or financial condition.
5. Dividend Restrictions:
Mortgage indentures, charter provisions and orders of regulatory
authorities place various restrictions on the use of the
subsidiaries' retained earnings for the payment of cash dividends
on their common stocks. At December 31, 1997, $27 million of
retained earnings were restricted. To pay dividends out of paid-in
capital the subsidiaries need regulatory approval.
6. Lines of Credit and Commitment Fees:
At December 31, 1997 and 1996, unused short-term bank lines of
credit were available in the amounts of $442 million and $409
million, respectively. In addition several of the subsidiaries
engaged in providing non-regulated energy services share a line of
credit under a revolving credit agreement. The amounts of credit
available under the revolving credit agreement were $330 million
and $100 million at December 31, 1997 and 1996, respectively. The
short-term bank lines of credit and the revolving credit agreement
require the payment of facility fees of approximately 1/10 of 1% on
the daily amount of such commitments.
Outstanding short-term debt consisted of:
December 31,
(Dollars In Thousands) 1997 1996
Balance Outstanding:
Notes Payable $199,285 $ 91,293
Commercial Paper 355,790 228,402
Total $555,075 $319,695
Year-End Weighted
Average Interest Rate:
Notes Payable 6.3% 6.2%
Commercial Paper 6.8% 7.2%
Total 6.6% 6.9%
7. Yorkshire Acquisition and UK Windfall Tax
In April 1997 the Company and New Century Energies, Inc. through an
equally owned joint venture, Yorkshire Power Group Limited (YPG),
acquired all of the outstanding shares of Yorkshire, an electric
distribution company in the UK. Total consideration paid by the
joint venture was approximately $2.4 billion which was financed by
a combination of equity and non-recourse debt. The Company uses
the equity method of accounting for its investment in YPG. The
Company's original investment in the joint venture was $360 million
and is included in other property and investments.
In July 1997 the British government enacted a new law that imposed
a one-time windfall tax on a revised privatization value which
originally had been computed in 1990 on certain privatized
utilities. The windfall tax is actually an adjustment of the
original privatization price by the UK government. The windfall
tax liability for Yorkshire Electricity Group plc is estimated to
be 134 million pounds sterling ($219 million) and is payable in two
equal installments. The first payment was made in December 1997
and the second installment will be due in December 1998. The
Company's $109.4 million share of the tax is reported as an
extraordinary loss. The equity earnings from the Yorkshire
investment, excluding the extraordinary loss, which are included in
nonoperating income, are $34 million inclusive of $10 million of
nonrecurring tax benefits related to a reduction of the UK
corporate income tax rate from 33% to 31% effective April 1, 1997.
The following amounts which are not included in AEP's consolidated
financial statements represent summarized consolidated financial
information of YPG at December 31, 1997 and for the nine-months
then ended:
Assets: (In Millions)
Property, Plant and Equipment $1,644.6
Current Assets 602.2
Other Assets 1,895.4
Total Assets $4,142.2
Capitalization and Liabilities:
Common Shareholders' Equity $ 542.1
Long-term Debt 704.3
Other Noncurrent Liabilities 488.7
Current Liabilities 2,407.1
Total Capitalization and Liabilities $4,142.2
Income Statement Data:
Operating Revenues $1,492.9
Operating Income 202.3
Income Before Extraordinary Item 67.5
Net Loss (151.3)
8. Benefit Plans:
AEP System Pension Plan - The AEP pension plan is a trusteed,
noncontributory defined benefit plan covering all employees meeting
eligibility requirements, except participants in the UMWA pension
plans. Benefits are based on service years and compensation
levels. The funding policy is to make annual contributions to a
qualified trust fund equal to the net periodic pension cost up to
the maximum amount deductible for federal income taxes, but not
less than the minimum required contribution in accordance with the
Employee Retirement Income Security Act of 1974.
Net AEP pension plan costs were computed as follows:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Service Cost-Benefits
Earned During the Year $ 36,000 $ 40,000 $ 30,400
Interest Cost on Projected
Benefit Obligation 128,600 119,500 116,700
Actual Return on Plan Assets (462,700) (302,400) (416,800)
Net Amortization (Deferral) 307,700 161,800 281,800
Net AEP Pension Plan Costs $ 9,600 $ 18,900 $ 12,100
AEP pension plan assets, actuarially computed benefit obligations
and the computation of accrued net pension plan liability are:
December 31,
1997 1996
(In Thousands)
Actuarial Present Value
of Benefit Obligation:
Vested Obligation $1,523,200 $1,377,000
Nonvested Obligation 161,000 136,500
Effects of Salary Progression 205,800 162,700
Projected Benefit Obligation 1,890,000 1,676,200
AEP Pension Plan Assets at
Fair Value (a) 2,370,300 2,009,500
Funded Status - AEP Pension Plan
Assets in Excess of Projected
Benefit Obligation 480,300 333,300
Unrecognized Prior
Service Cost 119,400 133,200
Unrecognized Net Gain on Assets (640,800) (488,200)
Unrecognized Net Transition
Assets (Being Amortized
Over 17 Years) (59,100) (68,900)
Accrued Net AEP Pension Plan
Liability $ (100,200) $ (90,600)
(a) AEP pension plan assets primarily consist of common stocks,
bonds and cash equivalents and are included in a separate entity
trust fund.
Assumptions used to determine AEP's net pension plan liability
were:
December 31,
1997 1996 1995
Discount Rate 7.00% 7.75% 7.25%
Average Rate of Increase in Compensation Levels 3.2% 3.2% 3.2%
Expected Long-Term Rate of Return on Plan Assets 9.0% 9.0% 9.0%
OPEB - The AEP System provides certain benefits other than pensions
for retired employees. Substantially all non-UMWA employees are
eligible for postretirement health care and life insurance if they
retire from active service after reaching age 55 and have at least
10 service years.
Postretirement medical benefits for UMWA employees at affiliated
mining operations who have or will retire after January 1, 1976 are
the liability of the OPCo coal-mining subsidiaries and are included
in the OPEB net costs and liability. They are eligible for
postretirement medical benefits if they retire from active service
after reaching age 55 and have at least 10 service years. In
addition, non-active UMWA employees will become eligible for
postretirement benefits at age 55 if they have had 20 years of
service.
The funding policy for AEP's OPEB plan is to make contributions
to an external Voluntary Employees Beneficiary Association trust
fund equal to the incremental OPEB costs (i.e., the amount that the
total postretirement benefits cost under SFAS 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions,"
exceeds the pay-as-you-go amount). Contributions were $35.2
million in 1997, $45.8 million in 1996 and $53 million in 1995. In
several jurisdictions the utility subsidiaries deferred the
increased OPEB costs resulting from the SFAS 106 required change
from pay-as-you-go to accrual accounting which were not being
recovered in rates. No additional deferrals were made in 1997 or
1996. At December 31, 1997 and 1996, $7.9 million and $14.5
million, respectively, of incremental OPEB costs were deferred.
Aggregate OPEB costs were computed as follows:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Service Cost $ 14,000 $ 15,300 $13,500
Interest Cost on Projected
Benefit Obligation 55,900 53,500 54,900
Net Amortization of the
Transition Obligation 32,000 32,300 32,000
Return on Plan Assets (44,100) (21,100) (25,400)
Net Amortization (Deferral) 21,500 9,900 16,800
Net OPEB Costs $ 79,300 $ 89,900 $91,800
OPEB assets, actuarially computed benefit obligations and the
computation of the accrued net OPEB liability are:
December 31,
1997 1996
(In Thousands)
Accumulated Postretirement
Benefit Obligation:
Active Employees Fully
Eligible for Benefits $ 73,800 $ 57,800
Current Retirees 466,900 423,000
Other Active Employees 309,000 245,600
Total Benefit Obligation 849,700 726,400
Fair Market Value of
Plan Assets (a) 311,900 232,500
Unfunded Benefit Obligation (537,800) (493,900)
Unrecognized Net Loss (Gain) 66,100 (3,300)
Unrecognized Net Transition
Obligation Being
Amortized Over 20 Years 416,400 448,500
Accrued Net OPEB Liability $ (55,300) $(48,700)
(a) Plan assets consist of cash surrender value of life insurance
contracts on certain employees owned by the trust and short-term
tax-exempt municipal bonds.
Assumptions used to determine OPEB's funded status were:
December 31,
1997 1996 1995
Discount Rate 7.00% 7.75% 7.25%
Expected Long-Term Rate
of Return on Plan Assets 8.75% 8.75% 8.75%
Initial Medical Cost Trend Rate 7.0% 7.5% 8.0%
Ultimate Medical Cost Trend Rate 4.25% 4.75% 4.5%
Medical Cost Trend Rate Decreases
to Ultimate Rate in Year 2005 2005 2005
Assuming a one percent increase in the medical cost trend rate, the
1997 OPEB cost for all employees, both non-UMWA and UMWA, would
increase by $10 million and the accumulated benefit obligations
would increase by $92 million.
AEP System Savings Plan - An employee savings plan is offered to
non-UMWA employees which allows participants to contribute up to
17% of their salaries into various investment alternatives,
including AEP common stock. An employer matching contribution,
equaling one-half of the employees' contribution to the plan up to
a maximum of 3% of the employees' base salary, is invested in AEP
common stock. The employer's annual contributions totaled $19.6
million in 1997, $19 million in 1996 and $18.8 million in 1995.
Other UMWA Benefits - The Company provides UMWA pension, health and
welfare benefits for certain employees, retirees, and their
survivors who meet eligibility requirements. The benefits are
administered by UMWA trustees and contributions are made to their
trust funds. Contributions based on hours worked are expensed as
paid as part of the cost of active mining operations and were not
material in 1997, 1996 and 1995. Based upon the UMWA actuary
estimate the Company's share of unfunded pension liability was $6.9
million at June 30, 1997. In the event the Company should
significantly reduce or cease mining operations or contributions to
the UMWA trust funds, a withdrawal obligation will be triggered for
both the pension and health and welfare plans. If the mining
operations had been closed on December 31, 1997 the estimated
withdrawal liability for all UMWA benefit plans would have been
$6.7 million.
9. Fair Value of Financial Instruments:
Nuclear Trust Funds Recorded at Market Value - The trust
investments, reported in other property and investments, are
recorded at market value in accordance with SFAS No. 115 and
consist of tax-exempt municipal bonds and other securities.
At December 31, 1997 and 1996 the fair values of the trust
investments were $566 million and $491 million, respectively.
Accumulated gross unrealized holding gains were $41 million
and $21.9 million at December 31, 1997 and 1996, respectively
and accumulated gross unrealized holding losses were
$1.2 million at both year-ends. The change in
market value in 1997, 1996, and 1995 was a net unrealized holding
gain of $19.1 million, $2.6 million and $24.9 million,
respectively.
The trust investments' cost basis by security type were:
December 31,
1997 1996
(In Thousands)
Tax-Exempt Bonds $335,358 $340,290
Equity Securities 74,398 54,389
Treasury Bonds 44,200 26,958
Corporate Bonds 9,167 7,977
Cash, Cash Equivalents and
Accrued Interest 63,392 40,430
Total $526,515 $470,044
Proceeds from sales and maturities of securities of $147.3 million
during 1997 resulted in $3.9 million of realized gains and $1.4
million of realized losses. Proceeds from sales and maturities of
securities of $115.3 million during 1996 resulted in $2.6 million
of realized gains and $2.1 million of realized losses. During 1995
proceeds from sales and maturities of securities of $78.2 million
resulted in $1.4 million of realized gains and $0.3 million of
realized losses. The cost of securities for determining realized
gains and losses is original acquisition cost including amortized
premiums and discounts.
At December 31, 1997, the year of maturity of trust fund
investments other than equity securities, was:
(In Thousands)
1998 $ 87,063
1999 - 2002 127,575
2003 - 2007 182,873
After 2007 54,606
Total $452,117
Other Financial Instruments Recorded at Historical Cost - The
carrying amounts of cash and cash equivalents, accounts receivable,
short-term debt, and accounts payable approximate fair value
because of the short-term maturity of these instruments. Fair
values for preferred stock subject to mandatory redemption were
$136 million and $517 million and for long-term debt were $5.7
billion and $5.0 billion at December 31, 1997 and 1996,
respectively. The carrying amounts on the financial statements for
preferred stock subject to mandatory redemption were $128 million
and $510 million and for long-term debt were $5.4 billion and $4.9
billion at December 31, 1997 and 1996, respectively. Fair values
are based on quoted market prices for the same or similar issues
and the current dividend or interest rates offered for instruments
of the same remaining maturities. The carrying amount of the spent
nuclear fuel disposal trust funds approximates the Company's best
estimate of the fair value of the pre-April 1983 SNF disposal
liability.
10. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Charged (Credited) to Operating Expenses (net):
Current $346,290 $375,528 $265,313
Deferred 11,124 (17,008) 22,990
Deferred Investment Tax Credits (16,134) (16,298) (16,276)
Total 341,280 342,222 272,027
Charged (Credited) to Nonoperating Income (net):
Current (16,038) (5,636) 11,325
Deferred (17,673) (4,470) (11,074)
Deferred Investment Tax Credits (9,107) (9,510) (9,543)
Total (42,818) (19,616) (9,292)
Total Federal Income Tax as Reported $298,462 $322,606 $262,735
The following is a reconciliation of the difference between
the amount of federal income taxes computed by multiplying book
income before federal income taxes by the statutory tax rate, and
the amount of federal income taxes reported.
Year Ended December 31,
1997 1996 1995
(In Thousands)
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $ 638,211 $628,856 $584,674
Extraordinary Loss (Note 7) (109,419) - -
Federal Income Taxes 298,462 322,606 262,735
Pre-Tax Book Income $ 827,254 $951,462 $847,409
Federal Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $289,539 $333,012 $296,593
Increase (Decrease) in Federal Income Tax
Resulting from the Following Items:
Depreciation 53,239 50,537 46,453
Corporate Owned Life Insurance (18,240) (12,009) (25,506)
Investment Tax Credits (net) (25,241) (25,813) (26,179)
Extraordinary Loss - UK Windfall Tax 38,297 - -
Other (39,132) (23,121) (28,626)
Total Federal Income Taxes as Reported $298,462 $322,606 $262,735
Effective Federal Income Tax Rate 36.1% 33.9% 31.0%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences:
December 31,
1997 1996
(In Thousands)
Deferred Tax Assets $ 807,226 $ 784,349
Deferred Tax Liabilities (3,368,147) (3,427,492)
Net Deferred Tax Liabilities $(2,560,921) $(2,643,143)
Property Related Temporary Differences $(2,161,484) $(2,162,099)
Amounts Due From Customers For Future
Federal Income Taxes (410,255) (428,698)
Deferred State Income Taxes (201,843) (229,429)
All Other (net) 212,661 177,083
Total Net Deferred Tax Liabilities $(2,560,921) $(2,643,143)
The Company has settled with the IRS all issues from the
audits of the consolidated federal income tax returns for the years
prior to 1991. Returns for the years 1991 through 1996 are
presently being audited by the IRS. During the audit the IRS
agents requested a ruling from their National Office that certain
interest deductions relating to COLI claimed by the Company for
1991 through 1993 should not be allowed. The Company filed a brief
with the IRS National Office refuting the agents' position.
Although no adjustments have been proposed, a disallowance of the
COLI interest deductions through December 31, 1997 would reduce
earnings by approximately $286 million (including interest). AEP
believes it has meritorious defenses and will vigorously contest
any proposed adjustments. No provisions for this amount have been
recorded. In the event the Company is unsuccessful it could have
a material adverse impact on results of operations and cash flows.
11. Leases:
Leases of property, plant and equipment are for periods up to
35 years and require payments of related property taxes,
maintenance and operating costs. The majority of the leases have
purchase or renewal options and will be renewed or replaced by
other leases.
Lease rentals are primarily charged to operating expenses in
accordance with rate-making treatment. The components of rentals
are as follows:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Operating Leases $257,042 $262,451 $259,877
Amortization of Capital Leases 104,732 114,050 101,068
Interest on Capital Leases 31,601 28,696 27,542
Total Rental Payments $393,375 $405,197 $388,487
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1997 1996
(In Thousands)
ELECTRIC UTILITY PLANT:
Production $ 47,246 $ 44,390
Transmission 3 6
Distribution 14,660 14,699
General:
Nuclear Fuel (net of amortization) 103,939 59,681
Mining Plant and Other 516,843 466,797
Total Electric Utility Plant 682,691 585,573
Accumulated Amortization 196,145 200,931
Net Electric Utility Plant 486,546 384,642
OTHER PROPERTY 57,763 33,439
Accumulated Amortization 5,917 3,854
Net Other Property 51,846 29,585
Net Property under Capital Leases $538,392 $414,227
Capital Lease Obligations:*
Noncurrent Liability $437,303 $324,674
Liability Due Within One Year 101,089 89,553
Total Capital Lease Obligations $538,392 $414,227
*Represents the present value of future minimum lease payments. The noncurrent
portion of capital lease obligations is included in other noncurrent liabilities
in the Consolidated Balance Sheet.
Properties under operating leases and related obligations
are not included in the Consolidated Balance Sheets.
Future minimum lease rentals, consisted of the following at
December 31, 1997:
Noncancelable
Capital Operating
Leases Leases
(In Thousands)
1998 $104,623 $ 243,042
1999 92,740 229,764
2000 79,507 228,044
2001 64,438 225,482
2002 59,400 220,111
Later Years 164,371 3,577,422
Total Future Minimum Lease Rentals 565,079 (a) $4,723,865
Less Estimated Interest Element 130,626
Estimated Present Value of Future
Minimum Lease Rentals 434,453
Unamortized Nuclear Fuel 103,939
Total $538,392
(a) Minimum lease rentals do not include nuclear fuel rentals. The rentals are
paid in proportion to heat produced and carrying charges on the unamortized
nuclear fuel balance. There are no minimum lease payment requirements for
leased nuclear fuel.
12. Supplementary Information:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Purchased Power - OVEC
(44.2% owned by AEP System) $29,631 $22,156 $10,546
Cash was paid for:
Interest (net of capitalized amounts) $390,491 $373,570 $395,169
Income Taxes $398,833 $404,297 $273,671
Noncash Acquisitions under Capital Leases $234,846 $136,988 $106,256
13. Capital Stocks and Paid-In Capital:
Changes in capital stocks and paid-in capital during the
period January 1, 1995 through December 31, 1997 were:
Cumulative Preferred Stocks
Shares of Subsidiaries
Cumulative Not Subject Subject to
Common Stock- Preferred Stocks Paid-in To Mandatory Mandatory
Par Value $6.50(a) of Subsidiaries Common Stock Capital Redemption Redemption(b)
(Dollars in Thousands)
January 1, 1995 194,234,992 8,236,251 $1,262,527 $1,640,661 $ 233,240 $590,385
Issuances 1,400,000 - 9,100 39,607 - -
Retirements and
Other - (1,526,500) - (21,744) (85,000) (67,650)
December 31, 1995 195,634,992 6,709,751 1,271,627 1,658,524 148,240 522,735
Issuances 1,600,000 - 10,400 55,061 - -
Retirements and
Other - (707,518) - 1,969 (57,917) (12,835)
December 31, 1996 197,234,992 6,002,233 1,282,027 1,715,554 90,323 509,900
Issuances 1,754,989 - 11,408 65,337 - -
Retirements and
Other - (4,258,947) - (2,109) (43,599) (382,295)
December 31, 1997 198,989,981 1,743,286 $1,293,435 $1,778,782 $ 46,724 $127,605
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
14. Unaudited Quarterly Financial Information:
Quarterly Periods Ended
1997
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,492,069 $1,382,158 $1,583,994 $1,703,147
Operating Income 271,978 221,255 275,090 216,131
Net Income Before
Extraordinary Item 172,562 121,139 201,746 124,933
Net Income 172,562 121,139 91,181 126,079
Earnings per Share
Before Extraordinary
Item* 0.92 0.64 1.07 0.66
Earnings per Share 0.92 0.64 0.48 0.66
*Amounts for 1997 do not add to $3.28 earnings per share due to
rounding.
The third quarter of 1997 includes an extraordinary loss of $110.6
million or $0.59 per share for a UK Windfall Tax which
retroactively adjusted upward Yorkshire's privatization price
discussed in Note 7.
Quarterly Periods Ended
1996
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,517,781 $1,400,941 $1,484,422 $1,446,090
Operating Income 292,122 220,625 259,745 235,480
Net Income 180,012 112,666 162,324 132,428
Earnings per Share 0.96 0.60 0.87 0.71
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1997
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% (c) $102-$110 932,403 467,236 $ 46,724
Subject to Mandatory Redemption:
5.90% - 5.92% (c)(d) (e) 1,950,000 388,100 $ 38,810
6.02% - 6-7/8% (c)(d) (f) 1,950,000 637,950 63,795
7% (g) (g) 250,000 250,000 25,000
Total Subject to Mandatory
Redemption (d) $127,605
______________________________________________________________________________________________________
December 31, 1996
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding Thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 903,233 $ 90,323
Subject to Mandatory Redemption (d):
5.90% - 5.92% (e) 1,950,000 1,904,000 $190,400
6.02% - 6-7/8% (f) 1,950,000 1,945,000 194,500
7% - 7-7/8% $107.80-$107.88 1,250,000 1,250,000 125,000
Total Subject to Mandatory
Redemption (d) $509,900
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call price plus accrued dividends.
The involuntary liquidation preference is $100 per share for all outstanding shares.
(b) As of December 31, 1997 the subsidiaries had 7,189,682, 22,200,000 and 7,579,435 shares of $100, $25
and no par value preferred stock, respectively, that were authorized but unissued.
(c) During the first quarter of 1997 preferred stock was reacquired in connection with a tender offer.
(d) Shares outstanding and related amounts are stated net of applicable retirements through sinking funds
(generally at par) and reacquisitions of shares in anticipation of future requirements. The
subsidiaries reacquired enough shares in 1997 to meet all sinking fund requirements on certain series
until 2008 and on certain series until 2009 when all remaining outstanding shares must be redeemed.
The sinking fund provisions of the series subject to mandatory redemption aggregate $5,000,000 each
for the years 2000, 2001 and 2002.
(e) Not callable prior to 2003; after that the call price is $100 per share.
(f) Not callable prior to 2000; after that the call price is $100 per share.
(g) With sinking fund. Redemption is restricted prior to 2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
December 31, 1997 1997 1996 1997 1996
(In Thousands)
FIRST MORTGAGE BONDS
1997-2000 7.20% 6.35%-9.15% 6-1/4%-9.15% $ 466,411 $ 383,671
2001-2006 7.10% 6%-8.95% 6%-8.95% 1,511,000 1,511,000
2021-2025 7.95% 7.10%-8.80% 7.10%-9.35% 1,120,419 1,276,750
INSTALLMENT PURCHASE CONTRACTS (a)
1998-2002 4.60% 3.70%-7-1/4% 4.10%-7-1/4% 189,500 209,500
2007-2025 6.45% 5.45%-7-7/8% 5.45%-7-7/8% 756,745 756,745
NOTES PAYABLE (b)
1997-2008 6.73% 5.29%-9.60% 5.29%-9.60% 671,681 282,681
JUNIOR DEBENTURES
2025 - 2027 8.17% 7.92%-8.72% 8%-8.72% 495,000 315,000
OTHER LONG-TERM DEBT (c) 250,357 182,943
Unamortized Discount (net) (37,196) (34,580)
Total Long-term Debt
Outstanding (d) 5,423,917 4,883,710
Less Portion Due Within One Year 294,454 86,942
Long-term Portion $5,129,463 $4,796,768
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are subject to periodic adjustment.
Certain series will be purchased on demand at periodic interest-adjustment dates. Letters of credit from
banks and standby bond purchase agreements support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan agreements and revolving
credit agreements with a number of banks and other financial institutions and unsecured medium term notes
issued to the public. At expiration all notes then issued and outstanding are due and payable. Interest
rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
(c) Other long-term debt consists of a liability along with accrued interest for disposal of spent nuclear
fuel (see Note 4 of the Notes to Consolidated Financial Statements) and financing obligation under sale lease
back agreements.
(d) Long-term debt outstanding at December 31, 1997 is payable as follows:
Principal Amount (in thousands)
1998 $ 294,454
1999 491,579
2000 321,286
2001 267,040
2002 484,533
Later Years 3,602,221
Total $5,461,113
Management's Responsibility
The management of American Electric Power Company, Inc. is
responsible for the integrity and objectivity of the information and
representations in this annual report, including the consolidated
financial statements. These statements have been prepared in conformity
with generally accepted accounting principles, using informed estimates
where appropriate, to reflect the Company's financial condition and
results of operations. The information in other sections of the annual
report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the
preparation of the financial statements and in the ongoing examination
of the Company's established internal control structure over financial
reporting. The Audit Committee, which consists solely of outside
directors and which reports directly to the Board of Directors, meets
regularly with management, Deloitte & Touche LLP - Certified Public
Accountants and the Company's internal audit staff to discuss
accounting, auditing and reporting matters. To ensure auditor
independence, both Deloitte & Touche LLP and the internal audit staff
have unrestricted access to the Audit Committee.
The financial statements have been audited by Deloitte & Touche
LLP, whose report appears on the next page. The auditors provide an
objective, independent review as to management's discharge of its
responsibilities insofar as they relate to the fairness of the Company's
reported financial condition and results of operations. Their audit
includes procedures believed by them to provide reasonable assurance
that the financial statements are free of material misstatement and
includes a review of the Company's internal control structure over
financial reporting.
Independent Auditors' Report
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the accompanying consolidated balance sheets of
American Electric Power Company, Inc. and its subsidiaries as of
December 31, 1997 and 1996, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years in
the period ended December 31, 1997. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for
our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of American
Electric Power Company, Inc. and its subsidiaries as of December 31,
1997 and 1996, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1997 in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 24, 1998