AMERICAN ELECTRIC POWER
1 Riverside Plaza
Columbus, Ohio 43215-2373
CONTENTS
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition
and Results of Operations
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Notes to Consolidated Financial Statements
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
Schedule of Consolidated Long-term Debt of Subsidiaries
Management's Responsibility
Independent Auditors' Report
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1996 1995 1994 1993 1992
INCOME STATEMENTS DATA
(in millions):
Operating Revenues $5,849 $5,670 $5,505 $5,269 $5,045
Operating Income 1,008 965 932 929 883
Net Income 587 530 500 354 468
December 31, 1996 1995 1994 1993 1992
BALANCE SHEETS DATA
(in millions):
Electric Utility Plant $18,970 $18,496 $18,175 $17,712 $17,509
Accumulated Depreciation
and Amortization 7,550 7,111 6,827 6,612 6,281
Net Electric Utility Plant $11,420 $11,385 $11,348 $11,100 $11,228
Total Assets $15,886 $15,902 $15,739 $15,362 $14,217
Common Shareholders' Equity 4,545 4,340 4,229 4,151 4,245
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory
Redemption 90 148 233 268 535
Subject to Mandatory
Redemption* 510 523 590 501 234
Long-term Debt* 4,884 5,057 4,980 4,995 5,311
Obligations Under Capital
Leases* 414 405 400 284 300
*Including portion due within one year
Year Ended December 31, 1996 1995 1994 1993 1992
COMMON STOCK DATA:
Earnings per Share $3.14 $2.85 $2.71 $1.92 $2.54
Average Number of Shares
Outstanding (in thousands) 187,321 185,847 184,666 184,535 184,535
Market Price Range: High $44-3/4 $40-5/8 $37-3/8 $40-3/8 $35-1/4
Low 38-5/8 31-1/4 27-1/4 32 30-3/8
Year-end Market Price 41-1/8 40-1/2 32-7/8 37-1/8 33-1/8
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 76.5% 84.1% 88.6% 125.2% 94.6%
Book Value per Share $24.15 $23.25 $22.83 $22.50 $23.01
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Business Outlook
With the issuance of two Federal Energy Regulatory Commission (FERC)
orders and the commencement of planning for retail competition at the state
level, we are in a better position to identify and develop strategies for
addressing the issues that face American Electric Power (AEP) and our
changing industry. We recognize that the conventional ways of maintaining
and enhancing shareholder value are becoming less effective as the industry
moves towards greater competition in the generation and sale of
electricity. The industry's transition to competition and customer choice
and the ability to fully recover costs are probably the most significant
factors affecting AEP's future profitability.
Although AEP has the financial strength, geographic reach, location and
cost structure to be an able competitor, no assurance can be given that AEP
can maintain this position in the future. However, we intend to make every
effort to maintain and strengthen our competitive position. We see a link
between a smooth transition to a competitive marketplace and the
maintaining and enhancing of shareholder value.
The new FERC orders facilitate increased competition in both the
generation and sale of bulk power to wholesale customers. They provide,
among other things, for open access to transmission facilities. AEP's
support of the FERC's open access transmission rule is evidenced by our
being among the first to file a comparability tariff, offering access to
our transmission grid at 143 interconnections to all parties under the same
terms and conditions available to AEP. This has provided AEP with greater
opportunities for transmission service revenues.
Although customer choice proposals and discussions are under way in the
states in which we operate, it is difficult to predict their result and the
timing of any resultant changes. We are actively involved in discussions
on the state and federal level regarding how best to transition to
competition in order to represent the best interests of our customers,
shareholders and employees. We favor a transition because we believe that
AEP will in the long-term fare better in a competitive market than under
continued regulation.
As 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 the new FERC orders provide, under
certain conditions, for recovery of stranded costs at the wholesale level,
the issue of stranded cost remains open at the much larger state retail
level.
Stranded Costs
Stranded costs occur when a customer switches to a new supplier for its
electric energy needs or when a component of the business, for example
generation, is no longer subject to cost-based regulation, creating the
issue of who pays for plant investment, purchased power or fuel contracts
both non-affiliated and affiliated, inventories, construction work in
progress, nuclear decommissioning, plant removal and shutdown costs,
previously deferred costs (regulatory assets) and other investments and
commitments that are no longer needed, economic or recoverable in a
competitive market. The amount of any stranded costs AEP may experience
depends on the timing of and the extent to which direct competition is
introduced to our business and the then-existing market price of energy.
Under the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
assets (deferred expenses) and liabilities (deferred revenues) are included
in the consolidated financial statements in accordance with regulatory
actions to match expenses and revenues in cost-based rates. In the event a
portion of the business no longer met the requirements of SFAS 71, net
regulatory assets would have to be written off for that portion of the
business. Among other requirements SFAS 71 requires that the rates charged
customers be cost based.
Our generation business is still cost-based regulated and should remain
so for at least three to five years as the industry transitions to full
competition. Although the recent FERC orders provide for competition in
the firm wholesale market, that market is a relatively small part of our
business and many of our firm wholesale sales are still under
cost-of-service contracts. We believe that enabling state legislation should
provide for a sufficient transition period to allow for the recovery of any
generation-related stranded costs and we are dedicating ourselves to work
with regulators, customers and legislators to accomplish both an orderly
transition and a reasonable and fair disposition of the stranded cost
issue.
We favor the recovery of stranded costs during a transition period in
which rates would be fixed or frozen and electric utilities would take
steps to achieve cost savings which would be used to reduce or eliminate
stranded costs. However, if electric utilities were to no longer be
cost-based regulated and it were not possible to recover stranded costs, the
results of operations and financial condition of AEP and other electric
utilities would be adversely affected.
Since state commissions have jurisdiction over the sale and distribution
of electricity to retail customers, we believe that state legislation and
regulation should shape the future competitive market for electricity while
federal legislation should seek to ensure reciprocity among the states and
a level playing field for all power suppliers. Presently states with
higher cost power, like California and Massachusetts, are aggressively
pursuing deregulation. The states AEP operates in, however, are generally
addressing the call for customer choice more cautiously and the transition
to competition is expected to evolve at an uneven pace across the states.
Restructuring/Functional Unbundling
In 1996 we took some major steps to maintain and enhance AEP's
competitive strength and made progress towards our long-term goal of
becoming the world's premier supplier of energy and related services. We
restructured our management and operations to allow us to comply with the
new FERC orders by separating our generation and energy sales operations
from our energy transmission delivery operations and to address increasing
competition among electric suppliers through distinct functional business
units. This has achieved and should continue to achieve staffing,
managerial and operating efficiencies. The generation and marketing
business units expect to eventually compete in an open market for
customers. Our energy delivery business will remain regulated and may
ultimately be subject to some form of incentive or performance-based
ratemaking while Corporate Development and Marketing will be working to
cultivate new but related non-regulated business opportunities.
Corporate Branding and Positioning
We are enhancing our marketing and customer service efforts with programs
like the Key Accounts Program which strives to build strong partnerships
with key customers in order to build customer loyalty. In 1996 AEP also
launched a series of new television commercials as part of a branding
campaign to inform our customers that we will be operating under the name
American Electric Power and that we are AEP: America's Energy Partner. The
commercials are intended to position AEP as more than just a supplier of
electricity. As we enter an increasingly competitive energy market we want
to be the energy and energy services provider of choice.
New Business Opportunities
In the non-rate-regulated environment, AEP offers energy consulting and
project management services both domestically and internationally and
contracts with other public utilities and government agencies for the
licensing of intellectual property and the delivery of energy services. In
1996 an AEP subsidiary and two Chinese companies formed a joint venture
company to finance and build a 250-megawatt electric generating facility in
China. AEP's share of the total cost of the facility is approximately $120
million and the project is expected to be operational in 1999.
On February 24, 1997 AEP and Public Service Company of Colorado with
equal interests in a joint venture announced a cash tender offer for
Yorkshire Electricity Group plc in the United Kingdom. The joint venture
proposes to pay $2.4 billion to acquire all of the stock of Yorkshire
Electricity. AEP's equity invest-ment, estimated to be $360 million, will
be made through its subsidiary AEP Resources Inc., initially using cash
borrowed under a revolving credit agreement. We consider the China
investment and Yorkshire tender offer as important steps in our long-term
goal to become the premier provider of energy and energy services
worldwide.
In addition to pursuing foreign power generation, transmission and
distribution investments we formed new subsidiaries in 1996 to explore
other new complementary business opportunities including AEP
Communications, Inc. which was formed to provide data transmission and
related telecommunications products and services. In January 1997 AEP
Communications, Inc. entered into an agreement with Sprint Communications,
Inc. to construct jointly a 150 mile fiber optic line between Charleston,
West Virginia and Roanoke, Virginia. Another new subsidiary AEP Power
Marketing is presently seeking approval to market and broker power outside
of our traditional service territory. Plans are also in place to commence
gas marketing. We are pursuing non-regulated related business
opportunities because we believe they offer the opportunity to earn
enhanced returns as compared with our traditional regulated business.
However, we recognize that these opportunities are generally riskier.
Investments in new business opportunities may be made after management
carefully assesses the risks versus the potential for enhanced shareholder
value.
Cost Containment
In 1996 we continued our efforts to reduce costs in order to maintain our
competitiveness. Reviews of our major processes led to decisions to
consolidate the management and operations of internal service functions
performed at multiple locations. Among the functions being consolidated
are fossil generation plant maintenance, nuclear operations support staff,
system operations, accounting and load research. A study of the Company's
procurement and supply chain operations led to cost reductions through
better inventory management, just-in-time delivery and the increased use of
electronic purchasing. Also in 1996 we completed the installation of an
activity based management budgeting system throughout the system. This
tool will enable managers to better analyze work and control costs. While
staff reductions and cost savings are being achieved in these and other
areas, expenses for new marketing and customer services and modern
efficient management information systems are being increased to prepare for
competition. These expenditures for the future should produce further
improvements and efficiencies, enabling AEP to maintain its position as a
low-cost producer.
Fuel Costs
Coal is 70% of the production cost of electricity for AEP. Although our
coal costs per unit of electricity (per Kwh) have declined by one-half in
constant dollars in the last 10 years, we recognize that we must continue
to manage our coal costs to continue to maintain our competitive position.
Approximately 15% of the coal we burn is supplied by affiliated mines; the
remainder is acquired under long-term contracts and in the spot market. As
long-term contracts expire we are negotiating with non-affiliated suppliers
to lower purchased coal costs. Efforts also continued in 1996 to reduce
the cost of affiliated coal. 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 recent 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 over the term of the agreement (through
2009) the Ohio jurisdictional portion of the current and deferred 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 $180 million after tax. However, should it
become apparent that the costs will not be recoverable from Ohio and/or
non-Ohio jurisdictional customers, the mines may have to be closed and
future earnings and possibly financial condition adversely affected. In
addition compliance with Phase II requirements of the Clean Air Act, 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 in a transition to competition,
future earnings 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. Net generation in 1996 for the Company's only nuclear plant,
the two-unit Donald C. Cook Nuclear Plant, located on the shores of Lake
Michigan, was 16,396 gigawatts, the highest in the plant's 20-year history.
The generation record was set in part due to Unit 2's best continuous run
in its history, 226 days, reached in December 1996. Refueling costs and
related outage time have been reduced. We also reduced nuclear staff
support costs in 1996 by relocating our Columbus-based nuclear management
and support staff to Michigan to consolidate it with the plant staff.
It is difficult to reduce nuclear generation costs since certain major
cost components are impacted by federal laws and Nuclear Regulatory
Commission (NRC) regulations. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of
spent nuclear fuel and high-level radioactive waste. By law we participate
in the Department of Energy's (DOE's) Spent Nuclear Fuel (SNF) disposal
program which is described in Note 4 of the Notes to Consolidated Financial
Statements. Since 1983 our customers have paid $254 million for the
disposal of spent nuclear fuel consumed at the Cook Nuclear Plant. Under
the provisions of the Nuclear Waste Policy Act, collections from customers
are to provide the DOE with money to build a 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 storage repository for SNF, the cost of both
temporary and permanent storage will continue to increase.
The cost to decommission the Cook Nuclear Plant is also affected by NRC
regulations and the DOE's SNF disposal program. Studies completed in 1994
estimate the cost to decommission the Cook Nuclear Plant and dispose of
low-level nuclear waste accumulation to range from $634 million to $988
million in 1993 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 Nuclear Plant
over its remaining life. However, AEP's future results of operations and
possibly its financial condition could be adversely affected if the cost of
spent nuclear fuel disposal and decommissioning continues to increase and
cannot be recovered in regulated rates or as a stranded cost in a future
competitive market.
Environmental Concerns
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. AEP has spent
millions of dollars to equip our facilities with the latest economical
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 to take a leadership role to foster
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 spent nuclear fuel.
Coal combustion by-products, which constitute the overwhelming percentage
of these materials, are typically disposed of or treated in captive
disposal facilities or are beneficially utilized. In addition, our
generating plants and transmission and distribution facilities have used
asbestos, polychlorinated biphenyls (PCBs) and other hazardous and
non-hazardous materials. We are currently incurring costs to safely dispose
of such substances, and additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund) addresses clean-up of hazardous substances at
disposal sites and authorized the United States Environmental Protection
Agency (Federal EPA) to administer the clean-up programs. As of year-end
1996, we are currently involved in litigation with respect to five sites
being overseen by the Federal EPA and have been named by the Federal EPA as
"Potentially Responsible Parties" (PRPs) for six other sites. There are
eight 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 such potential
liability. The 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 non-hazardous. 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 costs are incurred for cleanup, future results of
operations 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 Clean Air Act Amendments of 1990 (CAAA) to
issue rules to implement the law. In December 1996 Federal EPA issued
final rules governing nitrogen oxide emissions that must be met after
January 1, 2000 (Phase II of the CAAA). The final rules will require
substantial reductions in nitrogen oxide emissions from certain types of
power plant boilers including those in AEP's power plants. In December
1996 a group of utilities including AEP operating companies filed a
petition for review of the rules in a U.S. Court of Appeals and requested
expedited consideration of the appeal. The cost to comply with the
emission reductions required by the final rules is expected to be
substantial and could have a material adverse impact on results of
operations and possibly financial condition if these costs are not
recovered from customers.
Federal EPA is considering proposals to revise the existing ambient air
quality standard for ozone and to establish a new ambient air quality
standard for fine particulate matter. The rules being considered could
result in requirements for reductions of nitrogen oxides and sulfur dioxide
emitted from coal fired power plants and could have a significant impact on
AEP's operations. The proposals being considered are of particular concern
because they do not appear to have a sound scientific basis. The cost of
complying with any new emission reduction requirements imposed as a result
of the adoption of revised ambient air quality standards can not be
precisely determined but could be substantial. If Federal EPA ultimately
promulgates stricter ambient air quality standards, they could have a
material adverse impact on results of operations and possibly financial
condition if these costs are not recovered from customers.
Results of Operations
1996 was a good year for AEP with earnings the best since 1989 and total
shareholder return placing us among the best in our industry. We continued
to be well within our goal of being in the upper quartile of the companies
in the Standard & Poor's electric utility index, based on cumulative
three-year return.
Earnings Increase
In 1996 earnings increased 11% to $587 million or $3.14 per share from
$530 million or $2.85 per share in 1995. The increase is 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 earnings were severance pay charges recorded in 1995 in
connection with realigning operations and management and gains recorded in
1996 from emission allowance transactions.
Earnings increased 6% in 1995 to $530 million or $2.85 per share from
$500 million or $2.71 per share in 1994. The primary reason for the
earnings improvement was increased retail energy sales reflecting increased
usage and growth in the number of customers. Unseasonably warm weather in
the summer of 1995 and colder weather in the fourth quarter of 1995, were
the primary factors accounting for the increased usage. The positive
earnings impact of the increased sales was partly offset by the unfavorable
effect of severance pay.
Revenues And Sales Increase
Operating revenues increased 3% in 1996 and 1995. Increased wholesale
energy sales and transmission and coal conversion service revenues were the
primary reasons for the increase in 1996 revenues. In 1995 the revenue
increase resulted primarily from an increase in retail customers' energy
usage, growth in the number of retail customers and the effects of rate
increases.
The change in revenues can be analyzed as follows:
Increase (Decrease)
From Previous Year
(Revenues in Millions) 1996 1995
Amount % Amount %
Retail:
Price Variance $ (42.9) $ 46.5
Volume Variance 63.7 173.0
Fuel Cost Recoveries 15.0 (22.9)
35.8 0.7 196.6 4.2
Wholesale:
Price Variance (202.0) (39.3)
Volume Variance 317.3 10.8
Fuel Cost Recoveries (3.6) (4.6)
111.7 16.4 (33.1) (4.6)
Other Operating Revenues 31.4 2.2
Total $ 178.9 3.2 $165.7 3.0
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 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 commercial and industrial
customers increased 1% reflecting growth in the number of customers.
Wholesale revenues increased 16% in 1996 reflecting a 46% increase in
wholesale sales attributable largely to new wholesale transactions with
power marketers and other utilities. As the wholesale energy market
evolves into a competitive marketplace the Company intends to take
advantage of new ways to market and price electricity and related services.
During 1996 the Company provided coal conversion services resulting in 6.8
billion kilowatthours of electricity generated for power marketers and
certain other utilities under a new FERC-approved interruptible, contingent
sales tariff. As a result of these new sales, the average price per
kilowatthour was significantly less in 1996 than in 1995. Also
contributing to the increased wholesale sales was a new 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 encouraged
by the 1996 issuance of FERC open access transmission rules and AEP's
aggressive efforts to provide flexible and competitively priced
transmission services led to an increase in transmission service revenues.
As a result transmission revenues, which are recorded in other operating
revenues, increased by approximately $24 million.
The increase in 1995 operating revenues resulted primarily from a 4%
increase in energy sales to retail customers due mainly to increased usage
and continued growth in the number of customers in all retail customer
classes. Energy sales to residential customers, the most weather-sensitive
customer class, rose more than 6% in 1995 mainly as a result of increased
weather related usage in the last half of the year. Sales to commercial
and industrial customers rose 5% and 2%, respectively, reflecting the
effects of weather and the expanding economy.
Although revenues from wholesale customers declined in 1995, wholesale
energy sales increased by more than 1% largely due to increased short-term
sales made on an hourly basis to unaffiliated utilities. This type of
short-term sale is typically made when the unaffiliated utility can
purchase energy at a lower cost than the cost at which that utility can
generate the energy or when the customer is short on generating capacity.
Such sales increase in periods of extreme weather. The increase in 1995
wholesale energy sales occurred during the last six months of the year when
the summer was unseasonably warm and fall temperatures were colder compared
with the prior year. While wholesale energy sales increased, wholesale
revenues declined in 1995 reflecting increasing price related competition.
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 unaffiliated generating plant availability, the weather and the economy.
The recently adopted 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
1996 and prior years by the quantities of energy and services sold in
wholesale transactions. Future results of operations will be affected by
the quantity and price of wholesale transactions which often depends on the
weather and power plant availability.
Operating Expenses Increase
Operating expenses increased 3% in 1996 and 1995. 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. In 1995
increased rent and related operating costs of the newly installed Gavin
Plant flue gas desulfurization systems (scrubbers) and expenses related to
severance pay charges were the main reasons for the increase in operating
expenses. Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1996 1995
Amount % Amount %
Fuel and Purchased Power $ 61.2 3.8 $(119.7) (6.9)
Other Operation 25.9 2.2 181.3 18.1
Maintenance (39.0) (7.2) (2.4) (0.5)
Depreciation and Amortization 7.8 1.3 20.8 3.6
Taxes Other Than Federal
Income Taxes 9.4 1.9 (5.0) (1.0)
Federal Income Taxes 70.2 25.8 58.6 27.5
Total $135.5 2.9 $ 133.6 2.9
Fuel and purchased power expense increased in 1996 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.
Although generation increased 3% in 1995, fuel and purchased power
expense declined as a result of a decrease in the average cost of fossil
fuel resulting from reduced coal prices reflecting the renegotiation of
certain long-term coal contracts and other lower priced purchases under
existing and new contracts. Other factors which reduced fuel and purchased
power expense in 1995 were increased utilization of low cost nuclear
generation; decreased energy purchases due to the mild weather during the
first half of 1995 and the operation of fuel clause mechanisms. Changes in
fuel expense are generally deferred pending recovery in various fuel clause
mechanisms, as such they generally do not affect earnings.
The significant increase in other operation expense during 1995 was
primarily due to rent and other operating costs of the Gavin Plant
scrubbers which went into service in December 1994 and the first quarter of
1995; a $41 million ($27 million after-tax) provision for severance pay
recorded in 1995 related mainly to a functional realignment of operations;
and costs related to the development of a new activity based budgeting
system.
Maintenance expense decreased in 1996 due to the recovery of previously
expensed storm damage costs and reduced nuclear plant maintenance expense
due to workforce reductions and the reduction of contract labor at the Cook
Nuclear Plant.
The increases in federal income tax expense attributable to operations
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 in
1995 the effects of accrual adjustments for prior year tax returns.
Nonoperating Income
Nonoperating income decreased in 1996 due to the cost of the AEP branding
program and startup costs of the new business ventures. The increase in
nonoperating income in 1995 was mainly due to a 1994 loss of $8.2 million
on a demand side management investment.
Interest Charges and Preferred Stock Dividend Requirements
In 1996 interest charges and preferred stock dividend requirements
decreased as the Company's subsidiaries continued their refinancing
programs. The programs 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 re-flecting an increased average
balance of short-term debt outstanding.
Interest charges increased in 1995 mainly due to an increase in interest
on short-term debt resulting from a higher average interest rate in 1995 on
larger levels of outstanding short-term debt.
Common Dividend Remains Constant; Payout Ratio Decreases
The Company paid a quarterly dividend in 1996 of 60 cents a share
maintaining the annual dividend rate at $2.40 per share. The payout ratio
continued an improving trend to 76% in 1996 from 84% in 1995 and 89% in
1994. 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 complement our core competencies and
can maintain and improve shareholder value.
Liquidity and Capital Resources
Electric utility construction expenditures in the United States have
been declining in recent years due to slow growth in the demand for
electricity, environmental restrictions, and delays in obtaining approvals
to construct transmission facilities. Demand-side management programs such
as direct load control, interruptible load, energy efficiency, and other
demand and load reduction programs have lessened the need for new plant
expenditures. Also in some parts of the country substantial portions of
new generation additions have been by non-utility entities. AEP's
construction expenditures have followed the industry trend and have been
generally declining since 1991 when we last completed a new generating
facility. Our electric generating plant expenditures for 1996 accounted
for only 27% of the total electric utility plant expenditures, as compared
to the historic level of investment in electric generating plant of 49%.
Transmission and distribution (T&D) expenditures, on the other hand,
accounted for approximately 68% of expenditures, compared with the historic
investment level of 46%. Construction expenditures for our domestic
utility operations are estimated to be $2 billion over the next three years
with no major plant construction planned for our service territory. Total
T&D expenditures will be related to the improvement of and additions to
delivery facilities. Approximately 88% of the domestic construction
expenditures for the next three years will be financed internally.
Allowance for funds used during construction (AFUDC) accruals also declined
during this period. The decline in AFUDC in recent years is primarily due
to the decrease in the level of generation plant construction combined with
a decrease in interest rates.
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 historically preferred stock
and with additional capital contributions by the parent company. In 1996
short-term borrowing decreased by $45 million. At December 31, 1996
American Electric Power Co., Inc. (the parent company) and its utility
subsidiaries had unused short-term lines of credit of $409 million, and
several of AEP's subsidiaries engaged in providing non-regulated energy
services had an unused line of credit of $100 million available under a
revolving credit agreement. In February 1997 the credit available under
the revolving credit agreement was increased to $500 million. The sources
of funds available to the parent company are dividends from its
subsidiaries, short-term and long-term borrowings and, when necessary,
proceeds from the issuance of common stock. The parent company issued
1,600,000 shares in 1996, 1,400,000 shares in 1995 and 700,000 shares in
1994 of common stock through a Dividend Reinvestment Program raising $65
million, $49 million and $22 million, respectively. As a result of the
common stock issuances and the reduction in long-term debt over the past
several years, the common equity to capitalization ratio has steadily
improved. At December 31, 1996 the ratio increased to 45.3% from 43.1% at
year-end 1995 and from 42.1% at year-end 1994.
The debt and preferred stock coverages of the principal operating
subsidiaries remained strong in 1996.
Coverages at December 31, 1996
Mortgage and Preferred
Long-term Debt Stock
Appalachian Power Co. 3.98 1.99
Columbus Southern Power Co. 4.44 N/A
Indiana Michigan Power Co. 6.66 3.07
Kentucky Power Co. 3.22 N/A
Ohio Power Co. 6.62 3.63
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. The subsidiaries presently exceed
these minimum coverage requirements.
In January 1997 the Company announced a tender offer for certain
subsidiaries' preferred stock in conjunction with special meetings
scheduled to be held on February 28, 1997. The special meetings' purpose
is to consider amendments to the subsidiaries' articles of incorporation to
remove certain capitalization ratio requirements. These restrictions limit
the subsidiaries' financial flexibility and could place them at a
competitive disadvantage in the future. The amount paid to redeem the
preferred stock that is tendered could total as much as $514 million. The
subsidiaries expect to use a combination of short-term debt and unsecured
long-term debt to pay for the preferred stock tendered.
Litigation
AEP is involved in a number of legal proceedings and claims. While we
are unable to predict the outcome of such litigation, it is not expected
that the ultimate resolution of these matters will have a material adverse
effect on the results of operations and/or financial condition.
Effect of Inflation
Inflation affects AEP's cost of replacing utility plant and the cost of
operating and maintaining its plant. The rate-making process limits our
recovery to the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely
basis. However, economic gains that results from the repayment of long-term
debt with inflated dollars partly offset such losses.
Corporate Owned Life Insurance
In connection with the audit of AEP's 1991, 1992 and 1993 federal
income tax returns the Internal Revenue Service agents sought a ruling from
the IRS National Office that certain interest deductions relating to a
corporate owned life insurance (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.
Although no adjustments have been proposed, a disallowance of the COLI
interest deductions through December 31, 1996 would reduce earnings by
approxiately $247 million (including interest). AEP believes it will
ultimately prevail on this issue and will vigorously contest any
disallowance that may be assessed.
In 1996 Congress enacted legislation that prospectively phases out the
tax benefits for COLI interest deductions over a three year period
beginning in 1996. As a result the Company intends to restructure its COLI
program. The restructuring of the COLI program is not expected to have a
material impact on results of operations.
New Accounting Rules
In 1996 the Financial Accounting Standards Board (FASB) issued an
exposure draft "Accounting for Certain Liabilities Related to Closure or
Removal of Long-Lived Assets." The proposal suggests that the present
value of decommissioning and certain other closure or removal obligations
be recorded as a liability when the obligation is incurred. A
corresponding asset would be recorded in the plant investment account and
recovered through depreciation charges over the asset's life. A proposed
transition rule would require that an entity report in income the
cumulative effect of initially applying the new standard. The FASB is
reconsidering the exposure draft proposal. It is unclear at this time in
what manner the FASB will adopt the proposal. Until it becomes apparent
what the FASB will decide and how certain questions raised by the exposure
draft are resolved the Company cannot determine its impact.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
Year Ended December 31,
1996 1995 1994
OPERATING REVENUES $5,849,234 $5,670,330 $5,504,670
OPERATING EXPENSES:
Fuel and Purchased Power 1,686,754 1,625,531 1,745,245
Other Operation 1,210,027 1,184,158 1,002,822
Maintenance 502,841 541,825 544,312
Depreciation and Amortization 600,851 593,019 572,189
Taxes Other Than Federal Income Taxes 498,567 489,223 494,210
Federal Income Taxes 342,222 272,027 213,399
TOTAL OPERATING EXPENSES 4,841,262 4,705,783 4,572,177
OPERATING INCOME 1,007,972 964,547 932,493
NONOPERATING INCOME 2,212 20,204 11,485
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 1,010,184 984,751 943,978
INTEREST CHARGES (net) 381,328 400,077 389,240
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 41,426 54,771 54,726
NET INCOME $587,430 $529,903 $500,012
AVERAGE NUMBER OF SHARES OUTSTANDING 187,321 185,847 184,666
EARNINGS PER SHARE $3.14 $2.85 $2.71
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
Year Ended December 31,
1996 1995 1994
RETAINED EARNINGS JANUARY 1 $1,409,645 $1,325,581 $1,269,283
NET INCOME 587,430 529,903 500,012
DEDUCTIONS:
Cash Dividends Declared 449,353 445,831 443,101
Other (24) 8 613
RETAINED EARNINGS DECEMBER 31 $1,547,746 $1,409,645 $1,325,581
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
1996 1995 1994
OPERATING ACTIVITIES:
Net Income $587,430 $529,903 $500,012
Adjustments for Noncash Items:
Depreciation and Amortization 590,657 578,003 561,188
Deferred Federal Income Taxes (21,478) 11,916 (16,033)
Deferred Investment Tax Credits (25,808) (25,819) (31,275)
Amortization of Operating Expenses
and Carrying Charges (net) 55,458 53,479 16,022
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (39,049) (71,804) 34,302
Fuel, Materials and Supplies 35,831 457 (1,627)
Accrued Utility Revenues 32,953 (40,433) 2,419
Accounts Payable (13,915) (31,044) (7,959)
Taxes Accrued (6,019) 37,515 (26,521)
Other (net) 41,002 14,437 (52,803)
Net Cash Flows From
Operating Activities 1,237,062 1,056,610 977,725
INVESTING ACTIVITIES:
Construction Expenditures (577,691) (605,974) (643,457)
Proceeds from Sale of Property and Other 12,283 20,567 49,802
Net Cash Flows Used For
Investing Activities (565,408) (585,407) (593,655)
FINANCING ACTIVITIES:
Issuance of Common Stock 65,461 48,707 22,256
Issuance of Cumulative Preferred Stock - - 88,787
Issuance of Long-term Debt 407,291 523,476 411,869
Retirement of Cumulative Preferred Stock (70,761) (158,839) (35,949)
Retirement of Long-term Debt (601,278) (469,767) (445,636)
Change in Short-term Debt (net) (45,430) 48,140 38,009
Dividends Paid on Common Stock (449,353) (445,831) (443,101)
Net Cash Flows Used For
Financing Activities (694,070) (454,114) (363,765)
Net Increase (Decrease) in Cash and
Cash Equivalents (22,416) 17,089 20,305
Cash and Cash Equivalents January 1 79,955 62,866 42,561
Cash and Cash Equivalents December 31 $57,539 $79,955 $62,866
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In Thousands - Except Share Data)
December 31,
1996 1995
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 9,341,849 $ 9,238,843
Transmission 3,380,258 3,316,664
Distribution 4,402,449 4,184,251
General (including mining assets and nuclear fuel) 1,491,781 1,442,086
Construction Work in Progress 353,832 314,118
Total Electric Utility Plant 18,970,169 18,495,962
Accumulated Depreciation and Amortization 7,549,798 7,111,123
NET ELECTRIC UTILITY PLANT 11,420,371 11,384,839
OTHER PROPERTY AND INVESTMENTS 892,674 825,781
CURRENT ASSETS:
Cash and Cash Equivalents 57,539 79,955
Accounts Receivable:
Customers (less allowance for uncollectible
accounts of $3,692 in 1996 and $5,430 in 1995) 415,413 417,854
Miscellaneous 115,919 74,429
Fuel - at average cost 235,257 271,933
Materials and Supplies - at average cost 251,896 251,051
Accrued Utility Revenues 174,966 207,919
Prepayments and Other 103,891 98,717
TOTAL CURRENT ASSETS 1,354,881 1,401,858
REGULATORY ASSETS 1,889,482 1,979,446
DEFERRED CHARGES 328,139 310,377
TOTAL $15,885,547 $15,902,301
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31,
1996 1995
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock-Par Value $6.50:
1996 1995
Shares Authorized. .300,000,000 300,000,000
Shares Issued . . ..197,234,992 195,634,992
(8,999,992 shares were held in treasury) $ 1,282,027 $ 1,271,627
Paid-in Capital 1,715,554 1,658,524
Retained Earnings 1,547,746 1,409,645
Total Common Shareholders' Equity 4,545,327 4,339,796
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 90,323 148,240
Subject to Mandatory Redemption 509,900 515,085
Long-term Debt* 4,796,768 4,920,329
TOTAL CAPITALIZATION 9,942,318 9,923,450
OTHER NONCURRENT LIABILITIES 1,002,208 884,707
CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year* 86,942 144,597
Short-term Debt 319,695 365,125
Accounts Payable 206,227 220,142
Taxes Accrued 414,173 420,192
Interest Accrued 75,124 80,848
Obligations Under Capital Leases 89,553 89,692
Other 304,323 304,466
TOTAL CURRENT LIABILITIES 1,496,037 1,625,062
DEFERRED INCOME TAXES 2,643,143 2,656,651
DEFERRED INVESTMENT TAX CREDITS 404,050 430,041
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 240,598 249,875
DEFERRED CREDITS 157,193 132,515
CONTINGENCIES (Note 4)
TOTAL $15,885,547 $15,902,301
*See Accompanying Schedules on pages 36 - 37.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Significant Accounting Policies:
The American Electric Power System (AEP, AEP System or the Company) is a
public utility engaged in the generation, purchase, transmission and
distribution of electric power to over 2.9 million retail customers in its
seven state service territory which covers portions of Ohio, Michigan,
Indiana, Kentucky, West Virginia, Virginia and Tennessee. Electric power
is also supplied at wholesale to neighboring utility systems and power
marketers.
The organization of the AEP System consists of American Electric Power
Company, Inc., the parent holding company; seven electric utility operating
companies (utility subsidiaries); a generating subsidiary, AEP Generating
Company (AEPGEN); a service company, American Electric Power Service
Corporation (AEPSC); three active coal-mining companies and a group of
subsidiaries that complement utility activities. The following utility
subsidiaries pool their generating and transmission facilities and operate
them as an integrated system:
- - Appalachian Power Company (APCo)
- - Columbus Southern Power Company (CSPCo)
- - Indiana Michigan Power Company (I&M)
- - Kentucky Power Company (KEPCo)
- - Ohio Power Company (OPCo)
The remaining two utility subsidiaries, Kingsport Power Company and
Wheeling Power Company, are distribution companies that purchase power from
APCo and OPCo, respectively. AEPSC provides management and professional
services to the AEP System. The active coal-mining companies are wholly-owned
by OPCo and sell 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 megawatt (mw) generating units. The group of
subsidiaries that complement utility activities are engaged in providing
non-regulated energy services and are seeking and considering new business
opportunities domestically and internationally that will permit AEP to
utilize its expertise and core competencies.
Effective January 1, 1996, AEPSC and the seven utility subsidiaries
began operating as American Electric Power. There has been no change to
the legal names of these companies. The AEP System's operations are
divided into major business units which are managed centrally by AEPSC.
Rate Regulation - The AEP System is subject to regulation by the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act
of 1935 (1935 Act). The rates charged by the utility subsidiaries are
approved by the Federal Energy Regulatory Commission (FERC) or one of the
state utility commissions as applicable. The FERC regulates wholesale
rates and the state commissions regulate retail rates.
Principles of Consolidation - The consolidated financial statements include
American Electric Power Company, Inc. (AEPCo., Inc.) and its wholly-owned
subsidiaries consolidated with their wholly-owned subsidiaries.
Significant intercompany items are eliminated in consolidation.
Basis of Accounting - As the owner of cost-based rate-regulated electric
public utility companies, AEPCo., Inc.'s consolidated financial statements
reflect the actions of regulators that result in the recognition of
revenues and expenses in different time periods than enterprises that are
not rate regulated. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (deferred income) are recorded to reflect the economic effects
of regulation.
Use of Estimates - The preparation of these financial statements in
conformity with generally accepted accounting principles requires in
certain instances the use of management's estimates. Actual results could
differ from those estimates.
Utility Plant - Electric utility plant is stated at original cost and is
generally subject to first mortgage liens. Additions, major replacements
and betterments are added to the plant accounts. Retirements from the
plant accounts and associated removal costs, net of salvage, are deducted
from accumulated depreciation. The costs of labor, materials and overheads
incurred to operate and maintain utility plant are included in operating
expenses.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash
nonoperating income item that is recovered over the service life of utility
plant through depreciation and represents the estimated cost of borrowed
and equity funds used to finance construction projects. The average rates
used to accrue AFUDC were 6.09%, 6.91%, and 6.59% in 1996, 1995 and 1994,
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:
Composite
Functional Class Depreciation
of Property Annual 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 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 $1.49 per ton. These costs are included in the
cost of coal charged to fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include temporary
cash investments with original maturities of three months or less.
Sale of Receivables - Under an agreement that 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, 1995 and 1994, $50 million remained to be
collected and remitted to the buyer.
Operating Revenues - Revenues include the accrual of electricity consumed
but unbilled at month-end as well as billed revenues.
Fuel Costs - Fuel costs are matched with revenues in accordance with rate
commission orders. Generally in the retail jurisdictions, changes in fuel
costs are deferred or revenues accrued until approved by the regulatory
commission for billing 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 Donald C. Cook
Nuclear Plant (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 109, "Accounting for Income Taxes."
Under the liability method, deferred income taxes are provided for all
temporary differences between book cost and tax basis of assets and
liabilities which will result in a future tax consequence. Where the
flow-through method of accounting for temporary differences is reflected in
rates, deferred income taxes are recorded with related regulatory assets
and liabilities in accordance with SFAS 71.
Investment Tax Credits - Investment tax credits have been accounted for
under the flow-through method except where regulatory commissions have
reflected investment tax credits in the rate-making process on a deferral
basis. Deferred investment tax credits are being amortized over the life
of the related plant investment.
Debt and Preferred Stock - Gains and losses on reacquired debt are deferred
and amortized over the remaining term of the reacquired debt in accordance
with rate-making treatment. If the debt is refinanced the reacquisition
costs are deferred and amortized over the term of the replacement debt
commensurate with their recovery in rates.
Debt discount or premium and debt issuance expenses are amortized over
the term of the related debt, with the amortization included in interest
charges.
Redemption premiums paid to reacquire preferred stock are included in
paid-in capital and amortized to retained earnings in accordance with
rate-making treatment. The excess of par value over costs of preferred stock
reacquired to meet sinking fund requirements is credited to paid-in capital
and amortized to retained earnings.
Other Property and Investments - Excluding decommissioning and spent
nuclear fuel disposal trust funds, 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.
Due to the rate-making process, adjustments for unrealized gains and losses
are not reported in equity but result in adjustments to regulatory assets
and liabilities.
2. Rate Matters:
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 and reserved certain items including
emission allowances for later consideration in determining total fuel
recovery. The 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 fixed rate to
the extent the actual cost of coal burned at the Gavin Plant is below the
predetermined price. After November 2009 the price that OPCo can recover
for coal from its affiliated Meigs mine which supplies the Gavin Plant will
be limited to the lower of cost or the then-current market price. Pursuant
to these agreements the Company has deferred $28.5 million for future
recovery at December 31, 1996.
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 $180 million after tax at December 31,
1996.
The affiliated Muskingum and Windsor mines may have to close by January
2000 in order to comply with the Phase II requirements of the Clean Air Act
Amendments of 1990. 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 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions to match expenses and revenues in
cost-based rates. Regulatory assets are expected to be recovered in future
periods through the rate-making process and the 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 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.
Regulatory assets and liabilities are comprised of the following at:
December 31,
1996 1995
(In Thousands)
Regulatory Assets:
Amounts Due From Customers For
Future Income Taxes $1,459,086 $1,446,485
Rate Phase-in Plan Deferrals 27,249 74,402
Unamortized Loss on Reacquired Debt 107,305 109,551
Other 295,842 349,008
Total Regulatory Assets $1,889,482 $1,979,446
Regulatory Liabilities:
Deferred Investment Tax Credits $404,050 $430,041
Other Regulatory Liabilities* 86,609 86,347
Total Regulatory Liabilities $490,659 $516,388
* 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. In May 1992
the Public Utilities Commission of Ohio (PUCO) issued an order providing
for a phased in rate increase of $123 million to be implemented in three
steps over a two-year period and disallowed $165 million of Zimmer Plant
investment. CSPCo appealed the PUCO ordered Zimmer disallowance and
phase-in plan to the Ohio Supreme Court. In November 1993 the Supreme Court
issued a decision on CSPCo's appeal affirming the disallowance and finding
that the PUCO did not have statutory authority to order phased-in rates.
The Court instructed the PUCO to fix rates to provide gross annual revenues
in accordance with the law and to provide a mechanism to recover the
amounts deferred as regulatory assets under the phase-in order.
As a result of the Supreme Court decision, in January 1994 the PUCO
approved a 7.11% rate increase effective February 1, 1994. The increase is
comprised of a 3.72% base rate increase to complete the rate increase
phase-in and a temporary 3.39% surcharge, which will be in effect until the
deferrals are recovered, estimated to be 1997. In 1996, 1995 and 1994
$31.5 million, $28.5 million and $18.5 million, respectively, of net phase-in
deferrals were collected through the surcharge. The deferrals were
$15.4 million at December 31, 1996 and $46.9 million at December 31, 1995.
The recovery of amounts deferred under the phase-in plan and the increase
in rates to the full rate level did not affect net income. From the
in-service date of March 1991 until rates went into effect in May 1992
deferred carrying charges of $43 million were recorded on the Zimmer Plant
investment. Recovery of the deferred carrying charges will be sought in
the next PUCO base rate proceeding in accordance with the PUCO accounting
order that authorized the deferral.
The Rockport Plant consists of two 1,300 mw coal-fired units. I&M and
AEPGEN each own 50% of one unit (Rockport 1) and lease a 50% interest in
the other unit (Rockport 2) from unaffiliated lessors under an operating
lease. The gain on the sale and leaseback of Rockport 2 was deferred and
is being amortized, with related taxes, over the initial lease term which
expires in 2022. Rate phase-in plans in I&M's Indiana and FERC
jurisdictions for its share of Rockport 1 provide for the recovery and
straight-line amortization through 1997 of prior-year cost deferrals.
Unamortized deferred amounts under the phase-in plans were $11.9 million
and $27.5 million at December 31, 1996 and 1995, respectively.
Amortization was $16 million in 1996, 1995 and 1994.
4. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has made substantial
construction commitments for utility operations. Such commitments do not
presently include any expenditures for new generating capacity. The
aggregate construction program expenditures for 1997-1999 are estimated to
be $2 billion.
Long-term fuel supply contracts contain clauses for periodic
adjustments, and most jurisdictions have fuel clause mechanisms that
provide for recovery of changes in the cost of fuel with the regulators'
review and approval. The contracts are for various terms, the longest of
which extend to the year 2014, and contain various clauses that would
release the Company from its obligation under certain force majeure
conditions.
The AEP System has contracted to sell up to 1,350 mw of capacity on a
long-term basis to unaffiliated utilities. Certain contracts totaling 705
mw of capacity are unit power agreements requiring the delivery of energy
regardless of whether the unit capacity is available. The power sales
contracts expire from 1997 to 2010.
Tender Offer - On February 24, 1997 AEP and Public Service Company of
Colorado with equal interests in a joint venture announced a cash tender
offer for Yorkshire Electricity Group plc in the United Kingdom. The joint
venture proposes to pay $2.4 billion to acquire all of the stock of
Yorkshire Electricity. AEP's equity investment, estimated to be $360
million, will be made through its subsidiary AEP Resources Inc., initially
using cash borrowed under a revolving credit agreement.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Nuclear
Plant under licenses granted by the Nuclear Regulatory Commission. 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 and
financial condition could be negatively affected.
Nuclear Incident Liability - Public liability is limited by law to $8.9
billion should an incident occur at any licensed reactor in the United
States. Commercially available insurance provides $200 million of
coverage. In the event of a nuclear incident at any nuclear plant in the
United States the remainder of the liability would be provided by a
deferred premium assessment of $79.3 million on each licensed reactor
payable in annual installments of $10 million. As a result, I&M could be
assessed $158.6 million per nuclear incident payable in annual installments
of $20 million. The number of incidents for which payments could be
required is not limited.
Nuclear insurance pools and other insurance policies provide $3.6
billion of property damage, decommissioning and decontamination coverage
for the Cook Plant. Additional insurance provides coverage for extra costs
resulting from a prolonged accidental Cook Plant outage. Some of the
policies have deferred premium provisions which could be triggered by
losses in excess of the insurer's resources. The losses could result from
claims at the Cook Plant or certain other non-affiliated nuclear units.
I&M could be assessed up to $35.8 million under these policies.
Spent Nuclear Fuel Disposal - Federal law provides for government
responsibility for permanent spent nuclear fuel disposal and assesses
nuclear plant owners fees for spent fuel disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being collected from
customers and remitted to the U.S. Treasury. Fees and related interest of
$172 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, 1996, 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 $634 million
to $988 million in 1993 nondiscounted dollars. The wide range is caused by
variables in assumptions including the estimated length of time spent
nuclear fuel must be stored at the plant subsequent to ceasing operations.
This in turn depends on future developments in the federal government's
spent nuclear fuel disposal program. Continued delays in the federal fuel
disposal program can result in increased decommissioning costs. I&M is
recovering estimated decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most
recent decommissioning study at the time of the last rate proceeding. I&M
records decommissioning costs in other operation expense and records a
noncurrent liability equal to the decommissioning cost recovered in rates;
such amount was $27 million in 1996, $30 million in 1995 including $4
million of special deposits and $26 million in 1994. 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, 1996
I&M has recognized a decommissioning liability of $314 million which is
included in other noncurrent liabilities.
Litigation - The Company is involved in a number of legal proceedings and
claims. While management is unable to predict the ultimate outcome of
litigation, it is not expected that the resolution of these matters will
have a material adverse effect on the results of operations or financial
condition.
5. Dividend Restrictions:
Mortgage indentures, 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, 1996, $30 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, 1996 and 1995 unused short-term bank lines of credit were
available in the amounts of $409 million and $372 million, respectively.
Commitment fees of approximately 1/8 of 1% of the unused short-term lines
of credit are required to maintain the lines of credit. In addition
several of the subsidiaries engaged in providing non-regulated energy
services share a $100 million line of credit under a revolving credit
agreement which requires the payment of a commitment fee of approximately
1/8 of 1% of the unused balance. At December 31, 1996 no borrowings were
outstanding under the revolving credit agreement. In February 1997 the
credit available under this agreement was increased to $500 million.
Outstanding short-term debt consisted of:
December 31,
(Dollars In Thousands) 1996 1995
Balance Outstanding:
Notes Payable $ 91,293 $ 128,425
Commercial Paper 228,402 236,700
Total $319,695 $365,125
Year-End Weighted
Average Interest Rate:
Notes Payable 6.2% 6.1%
Commercial Paper 7.2% 6.1%
Total 6.9% 6.1%
7. Benefit Plans:
AEP System Pension Plan - The AEP pension plan is a trusteed,
noncontributory defined benefit plan covering all employees meeting
eligibility requirements, except participants in the United Mine Workers of
America (UMWA) pension plans. Benefits are based on service years and
compensation levels. The funding policy is to make annual 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,
1996 1995 1994
(In Thousands)
Service Cost-Benefits Earned
During the Year $ 40,000 $ 30,400 $ 40,000
Interest Cost on Projected Benefit
Obligation 119,500 116,700 114,500
Actual Return on Plan Assets (302,400) (416,800) (6,700)
Net Amortization (Deferral) 161,800 281,800 (123,300)
Net AEP Pension Plan Costs $ 18,900 $ 12,100 $ 24,500
AEP pension plan assets and actuarially computed benefit obligations are:
December 31,
1996 1995
(In Thousands)
AEP Pension Plan Assets at
Fair Value (a) $2,009,500 $1,805,300
Actuarial Present Value
of Benefit Obligation:
Vested 1,377,000 1,321,600
Nonvested 136,500 147,400
Accumulated Benefit
Obligation 1,513,500 1,469,000
Effects of Salary Progression 162,700 181,000
Projected Benefit
Obligation 1,676,200 1,650,000
Funded Status - AEP
Pension Plan Assets
in Excess of Projected
Benefit Obligation 333,300 155,300
Unrecognized Prior
Service Cost 133,200 147,000
Unrecognized Net Gain (488,200) (295,200)
Unrecognized Net Transition
Assets (Being Amortized
Over 17 Years) (68,900) (78,700)
Accrued Net AEP
Pension Plan
Liability $ (90,600) $ (71,600)
(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 pension plan's funded status were:
December 31,
1996 1995 1994
Discount Rate 7.75% 7.25% 8.5%
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% 8.5%
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 million in 1996, $18.8 million in 1995 and $18.6
million in 1994.
UMWA Pension Plans - The coal-mining subsidiaries of OPCo provide UMWA
pension benefits for UMWA employees meeting eligibility requirements.
Benefits are based on age at retirement and years of service. As of June
30, 1996, the UMWA actuary estimates the OPCo coal-mining subsidiaries'
share of the UMWA pension plans' unfunded vested liabilities was
approximately $26 million. In the event the OPCo coal-mining subsidiaries
cease or significantly reduce mining operations or contributions to the
UMWA pension plans, a withdrawal obligation may be triggered for all or a
portion of their share of the unfunded vested liability. Contributions are
based on the number of hours worked, are expensed when paid and totaled
$1.6 million in 1996, $1.4 million in 1995 and $1.6 million in 1994.
Postretirement Benefits Other Than Pensions (OPEB) - The AEP System
provides certain other benefits for retired employees. Substantially all
non-UMWA employees are eligible for postretirement health care and life
insurance if they 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. 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 service years.
The funding policy for AEP's 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 $45.8 million in 1996, $53 million in 1995 and $29.5
million in 1994. 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 1996. At
December 31, 1996 and 1995, $14.5 million and $24.6 million, respectively,
of incremental OPEB costs were deferred.
Aggregate OPEB costs were computed as follows:
Year Ended December 31,
1996 1995 1994
(In Thousands)
Service Cost $ 15,300 $ 13,500 $16,500
Interest Cost on Projected
Benefit Obligation 53,500 54,900 47,300
Net Amortization of
Transition Obligation 32,300 32,000 31,100
Return on Plan Assets (21,100) (25,400) 900
Net Amortization (Deferral) 9,900 16,800 (6,800)
Net OPEB Costs $ 89,900 $ 91,800 $89,000
OPEB assets and actuarially computed benefit obligations are:
December 31,
1996 1995
(In Thousands)
Fair Market Value of
Plan Assets (a) $ 232,500 $ 165,600
Accumulated Postretirement
Benefit Obligation:
Active Employees Fully
Eligible for Benefits 57,800 59,200
Current Retirees 423,000 398,400
Other Active Employees 245,600 282,400
Total Benefit Obligation 726,400 740,000
Unfunded Benefit Obligation (493,900) (574,400)
Unrecognized Net Loss (Gain) (3,300) 48,500
Unrecognized Net Transition
Obligation Being
Amortized Over 20 Years 448,500 485,600
Accrued Net OPEB Liability $ (48,700) $ (40,300)
(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,
1996 1995 1994
Discount Rate 7.75% 7.25% 8.5%
Expected Long-Term Rate
of Return on Plan Assets 8.75% 8.75% 8.25%
Initial Medical Cost
Trend Rate 7.5% 8.0% 8.0%
Ultimate Medical Cost
Trend Rate 4.75% 4.5% 5.25%
Medical Cost Trend Rate
Decreases to Ultimate
Rate in Year 2005 2005 2005
Assuming a one percent increase in the medical cost trend rate, the 1996
OPEB cost for all employees, both non-UMWA and UMWA, would increase by $8
million and the accumulated benefit obligations would increase by $82
million.
Several UMWA health plans pay the postretirement medical benefits for
the Company's UMWA retirees who retired before January 2, 1976 and their
survivors plus retirees and others whose last employer is no longer a
signatory to the UMWA contract or is no longer in business. The UMWA
health plans are funded by payments from current and former UMWA wage
agreement signatories, the 1950 UMWA Pension Plan surplus and the Abandoned
Mine Land Reclamation Fund Surplus. Required annual payments to the UMWA
health funds made by AEP's active and inactive coal-mining subsidiaries
were recognized as expense when paid and totaled $0.9 million in 1996, $2.8
million in 1995 and $3.1 million in 1994.
By law, excess Black Lung Trust funds may be used to pay certain
postretirement medical benefits under one of the UMWA health plans. Excess
AEP Black Lung Trust funds used to reimburse the coal companies totaled
$7.4 million in 1996, $7.9 million in 1995 and $6.9 million in 1994. The
Black Lung Trust had excess funds at December 31, 1996 of approximately $12
million, of which $10.8 million may be used to pay future costs.
8. Fair Value of Financial Instruments:
Nuclear Trust Funds Recorded at Market Value - The trust investments,
reported in other property and investments, are recorded at market value in
accordance with SFAS 115 and consist of long-term tax-exempt municipal
bonds and other securities.
At December 31, 1996 and 1995 the fair values of the trust investments
were $491 million and $434 million, respectively. Accumulated gross
unrealized holding gains were $21.9 million and $19.1 million and
accumulated gross unrealized holding losses were $1.2 million and $1
million at December 31, 1996 and 1995, respectively. The change in market
value in 1996 was a net unrealized holding gain of $2.6 million, in 1995 a
net unrealized holding gain of $24.9 million and in 1994 a net unrealized
holding loss of $27.1 million.
The trust investments' cost basis by security type were:
December 31,
1996 1995
(In Thousands)
Tax-Exempt Bonds $340,290 $336,073
Equity Securities 54,389 24,101
Treasury Bonds 26,958 12,992
Corporate Bonds 7,977 1,971
Cash, Cash Equivalents
and Accrued Interest 40,430 40,356
Total $470,044 $415,493
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. Proceeds from sales and maturities of securities of $78.2
million during 1995 resulted in $1.4 million of realized gains and $0.3
million of realized losses. During 1994 proceeds from sales and maturities
of securities of $20.1 million resulted in $52,000 of realized gains and
$155,000 of realized losses. The cost of securities for determining
realized gains and losses is original acquisition cost including amortized
premiums and discounts.
At December 31, 1996, the year of maturity of trust fund investments
other than equity securities, was:
(In Thousands)
1997 $ 56,452
1998 - 2001 120,327
2002 - 2006 163,250
After 2006 75,626
Total $415,655
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 $517 million and $544 million and for long-term
debt were $5.0 billion and $5.3 billion at December 31, 1996 and 1995,
respectively. The carrying amounts on the financial statements for
preferred stock subject to mandatory redemption were $510 million and $523
million and for long-term debt were $4.9 billion and $5.1 billion at
December 31, 1996 and 1995, 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 pre-April 1983 spent nuclear fuel disposal
liability approximates the Company's best estimate of its fair value.
9. Federal Income Taxes:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1996 1995 1994
(In Thousands)
Charged (Credited) to Operating Expenses (net):
Current $375,528 $265,313 $240,655
Deferred (17,008) 22,990 (10,177)
Deferred Investment Tax Credits (16,298) (16,276) (17,079)
Total 342,222 272,027 213,399
Charged (Credited) to Nonoperating Income (net):
Current (5,636) 11,325 (2,907)
Deferred (4,470) (11,074) (5,856)
Deferred Investment Tax Credits (9,510) (9,543) (14,196)
Total (19,616) (9,292) (22,959)
Total Federal Income Tax as Reported $322,606 $262,735 $190,440
The following is a reconciliation of the difference between the amount of federal
incometaxes 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,
1996 1995 1994
(In Thousands)
Income Before Preferred Stock Dividend
Requirements of Subsidiaries $628,856 $584,674 $554,738
Federal Income Taxes 322,606 262,735 190,440
Pre-Tax Book Income $951,462 $847,409 $745,178
Federal Income Tax on Pre-Tax Book
Income at Statutory Rate (35%) $333,012 $296,593 $260,812
Increase (Decrease) in Federal Income
Tax Resulting from the Following Items:
Depreciation 50,537 46,453 31,212
Removal Costs (15,327) (14,640) (13,818)
Corporate Owned Life Insurance (12,009) (25,506) (22,970)
Investment Tax Credits (net) (25,813) (26,179) (31,273)
Federal Income Tax Accrual Adjustments - - (16,100)
Other (7,794) (13,986) (17,423)
Total Federal Income Taxes as Reported $322,606 $262,735 $190,440
Effective Federal Income Tax Rate 33.9% 31.0% 25.6%
The following tables show the elements of the net deferred tax liability and the significant
temporary differences:
December 31,
1996 1995
(In Thousands)
Deferred Tax Assets $ 784,349 $ 723,196
Deferred Tax Liabilities (3,427,492) (3,379,847)
Net Deferred Tax Liabilities $(2,643,143) $ 2,656,651)
Property Related Temporary Differences $(2,162,099) $(2,139,387)
Amounts Due From Customers For Future
Federal Income Taxes (428,698) (442,311)
Deferred State Income Taxes (229,429) (183,981)
All Other (net) 177,083 109,028
Total Net Deferred Tax Liabilities $(2,643,143) $(2,656,651)
The Company has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for
the years prior to 1991. Returns for the years 1991 through 1993 are
presently being audited by the IRS. During the audit the IRS agents
requested a ruling from their National Office that certain interest
deductions relating to corporate owned life insurance (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, 1996 would reduce earnings by
approximately $247 million (including interest). AEP believes it will
ultimately prevail on this issue and will vigorously contest any
adjustments that may be assessed. Accordingly, no provision for this
amount has been recorded. In the opinion of management, the final
settlement of open years will not have a material effect on results of
operations.
10. Leases:
Leases of property, plant and equipment are for periods up to 35 years
and require payments of related property taxes, maintenance and operating
costs. The majority of the leases have purchase or renewal options and
will be renewed or replaced by other leases.
Lease rentals are primarily charged to operating expenses in
accordance with rate-making treatment. The components of rentals are as
follows:
Year Ended December 31,
1996 1995 1994
(In Thousands)
Operating Leases $262,451 $259,877 $233,805
Amortization of Capital Leases 114,050 101,068 79,116
Interest on Capital Leases 28,696 27,542 23,280
Total Rental Payments $405,197 $388,487 $336,201
Properties under capital leases and related obligations on the Consolidated Balance
Sheets are as follows:
December 31,
1996 1995
(In Thousands)
ELECTRIC UTILITY PLANT:
Production $ 44,390 $ 44,849
Transmission 6 7
Distribution 14,699 14,753
General:
Nuclear Fuel (net of amortization) 59,681 69,442
Mining Plant and Other 466,797 424,952
Total Electric Utility Plant 585,573 554,003
Accumulated Amortization 200,931 179,952
Net Electric Utility Plant 384,642 374,051
OTHER PROPERTY 33,439 34,536
Accumulated Amortization 3,854 3,994
Net Other Property 29,585 30,542
Net Property under Capital Leases $414,227 $404,593
Obligations under Capital Leases $414,227 $404,593
Less Portion Due Within One Year 89,553 89,692
Noncurrent Capital Lease Liability $324,674 $314,901
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, 1996:
Noncancelable
Capital Operating
Leases Leases
(In Thousands)
1997 $ 90,813 $ 240,923
1998 73,817 232,903
1999 63,356 230,994
2000 53,027 229,039
2001 41,634 225,733
Later Years 150,278 3,858,008
Total Future Minimum Lease Rentals 472,925 (a) $5,017,600
Less Estimated Interest Element 118,379
Estimated Present Value of Future
Minimum Lease Rentals 354,546
Unamortized Nuclear Fuel 59,681
Total $414,227
(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.
11. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1996 1995 1994
(In Thousands)
Purchased Power - Ohio Valley Electric Corp.
(44.2% owned by AEP) $22,156 $10,546 $5,755
Cash was paid for:
Interest (net of capitalized amounts) $373,570 $395,169 $379,361
Income Taxes $404,297 $273,671 $312,233
Noncash Acquisitions under
Capital Leases were $136,988 $106,256 $227,055
12. CAPITAL STOCKS AND PAID-IN CAPITAL:
Changes in capital stocks and paid-in capital during the period January 1, 1994 through December 31, 1996 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, 1994 193,534,992 7,687,768 $1,257,977 $1,624,176 $ 268,240 $ 500,537
Issuances 700,000 900,000 4,550 17,706 - 90,000
Retirements and Other - (351,517) - (1,221) (35,000) (152)
December 31, 1994 194,234,992 8,236,251 1,262,527 1,640,661 233,240 590,385
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
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
13. Unaudited Quarterly Financial Information:
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
Quarterly Periods Ended
1995
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,416,169 $1,305,342 $1,523,390 $1,425,429
Operating Income 257,556 211,284 262,548 233,159
Net Income 147,850 96,478 154,156 131,419
Earnings per Share 0.80 0.52 0.83 0.70
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF
SUBSIDIARIES
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% (c) $102-$110 932,403 903,233 $ 90,323
Subject to Mandatory Redemption (d):
5.90% - 5.92% (c) (e) 1,950,000 1,904,000 $190,400
6.02% - 6-7/8% (c) (f) 1,950,000 1,945,000 194,500
7% - 7-7/8% (c) $107.80-$107.88(g) 1,250,000 1,250,000 125,000
Total Subject to Mandatory
Redemption (h) $509,900
______________________________________________________________________________________________________
December 31, 1995
Call
Price per Shares Shares Amount (in
Share (a) Authorized Outstanding thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 932,403 $ 93,240
7.08% - 7.40% $101.85-$102.11 550,000 550,000 55,000
Total Not Subject to Mandatory
Redemption $148,240
Subject to Mandatory Redemption (d):
4.50% $102 19,625 2,348 $ 235
5.90% - 5.92% (e) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (f) 1,950,000 1,950,000 195,000
7% - 7-7/8% $107.80-$107.88(g) 1,250,000 1,250,000 125,000
9.50% (i) 750,000 75,000 7,500
Total Subject to Mandatory
Redemption (h) 522,735
Less Portion Due Within One Year 7,650
Long-term Portion $515,085
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, 1996 the subsidiaries had 4,708,320, 22,200,000 and 5,801,850 shares of $100, $25
and no par value preferred stock, respectively, that were authorized but unissued.
(c) In January 1997 a tender offer for certain series of preferred stock was announced. In conjunction
with the tender offer a special shareholders meeting is scheduled to be held on February 28, 1997 for the
purpose of considering amendments to the subsidiaries' articles of incorporation to remove certain
capitalization ratio requirements.
(d) With sinking fund. Shares outstanding and related amounts are stated net of applicable retirements
through sinking funds (generally at par) and reacquisitions of shares in anticipation of future
requirements.
(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) Redemption is restricted prior to 1997.
(h) The sinking fund provisions of the series subject to mandatory redemption aggregate $5,000,000,
$5,000,000, $16,000,000 and $16,000,000 in 1998, 1999, 2000 and 2001, respectively.
(i) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share.
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, 1996 1996 1995 1996 1995
(in thousands)
FIRST MORTGAGE BONDS
1996-1999 7.35% 6-1/4%-9.15% 5%-9.15% $ 383,671 $ 496,866
2001-2006 7.10% 6%-8.95% 6%-9.31% 1,511,000 1,530,020
2020-2025 8.07% 7.10%-9.35% 7.10%-9-7/8% 1,276,750 1,473,127
INSTALLMENT PURCHASE CONTRACTS (a)
1998-2002 4.80% 4.10%-7-1/4% 5%-7-1/4% 209,500 209,500
2007-2025 6.45% 5.45%-7-7/8% 5.45%-7-7/8% 756,745 756,745
NOTES PAYABLE (b)
1996-2008 7.31% 5.29%-9.60% 5.29%-10.78% 282,681 221,000
DEBENTURES
1996 - 1999 (c) - - 5-1/8%-7-7/8% - 30,759
2025 - 2026 8.28% 8%-8.72% 8.16%-8.72% 315,000 200,000
OTHER LONG-TERM DEBT (d) 182,943 172,403
Unamortized Discount (net) (34,580) (33,144)
Total Long-term Debt
Outstanding (e) 4,883,710 5,057,276
Less Portion Due Within One Year 86,942 136,947
Long-term Portion $4,796,768 $4,920,329
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 with a number of
banks and other financial institutions. At expiration all notes then issued and outstanding are due and
payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term
interest rates.
(c) All sinking fund debentures were reacquired on March 1, 1996.
(d) Other long-term debt consists primarily of a liability along with accrued interest for disposal of spent
nuclear fuel (see Note 4 of the Notes to Consolidated Financial Statements).
(e) Long-term debt outstanding at December 31, 1996 is payable as follows:
Principal Amount (in thousands)
1997 $ 86,942
1998 224,274
1999 210,678
2000 183,652
2001 252,575
Later Years 3,960,169
Total $4,918,290
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, 1996
and 1995, and the related consolidated statements of income, retained
earnings, and cash flows for each of the three years in the period ended
December 31, 1996. 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, 1996 and 1995, and
the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1996 in conformity with generally
accepted accounting principles.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Columbus, Ohio
February 25, 1997