AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31, 1995 1994 1993 1992 1991
INCOME STATEMENTS DATA
(in millions):
Operating Revenues $5,670 $5,505 $5,269 $5,045 $5,047
Operating Income 965 932 929 883 918
Net Income 530 500 354 468 498
December 31, 1995 1994 1993 1992 1991
BALANCE SHEETS DATA (in millions):
Electric Utility Plant $18,496 $18,175 $17,712 $17,509 $17,148
Accumulated Depreciation
and Amortization 7,111 6,827 6,612 6,281 5,952
Net Electric Utility Plant $11,385 $11,348 $11,100 $11,228 $11,196
Total Assets $15,902 $15,739 $15,362 $14,217 $13,824
Common Shareholders' Equity 4,340 4,229 4,151 4,245 4,221
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 148 233 268 535 535
Subject to Mandatory Redemption* 523 590 501 234 141
Long-term Debt* 5,057 4,980 4,995 5,311 5,029
Obligations Under Capital Leases* 405 400 284 300 273
*Including portion due within one year
Year Ended December 31, 1995 1994 1993 1992 1991
COMMON STOCK DATA:
Earnings per Share $2.85 $2.71 $1.92 $2.54 $2.70
Average Number of Shares
Outstanding (in thousands) 185,847 184,666 184,535 184,535 184,535
Market Price Range: High $40-5/8 $37-3/8 $40-3/8 $35-1/4 $34-1/4
Low 31-1/4 27-1/4 32 30-3/8 26-5/8
Year-end Market Price 40-1/2 32-7/8 37-1/8 33-1/8 34-1/4
Cash Dividends Paid $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio 84.1% 88.6% 125.2% 94.6% 88.9%
Book Value per Share $23.25 $22.83 $22.50 $23.01 $22.88
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Business Conditions
The prospect for market driven rates is powering a movement to introduce
direct competition to the generation function of the electric utility
industry. As a result we expect that competition will be a factor
influencing AEP s future results of operations. Other important factors that
could affect future results of operations are environmental laws, affiliated
coal mining costs, nuclear fuel storage and disposal costs and nuclear
decommissioning costs. Management will be working to prepare for a
transition to greater competition and to manage the other major factors that
could impact future results of operations.
Competition at the Wholesale Level
The Energy Policy Act of 1992 (Energy Act) was designed, among other
things, to foster competition in the wholesale market through amendments to
(a) the Public Utility Holding Company Act, facilitating the ownership and
operation of generating facilities by independent power producers including
non-electric utilities and (b) the Federal Power Act, authorizing the Federal
Energy Regulatory Commission (FERC) under certain conditions to order
utilities which own transmission facilities to provide wholesale transmission
services to other utilities and entities generating electric power. While
the Energy Act gave the FERC broad authority to mandate transmission access
in the wholesale market, it prohibited the FERC from ordering retail
transmission access.
Customer Choice
The demand for customer choice of electric supplier is mainly coming
from large industrial energy users. Transmission access in the retail
marketplace will allow an electric customer within a particular utility s
service territory to buy power directly from another source using the power
lines of the local electric utility for delivery.
Financial Implications of Competition
A significant expansion of competition in the generation of electricity
would require the resolution of many complex issues, including the obligation
to serve and the recovery of stranded costs which, if not properly addressed,
could adversely impact future results of operations and possibly the
financial condition of electric utilities.
Stranded costs occur when a customer switches to a new supplier for its
electric energy needs 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 costs,
and other investments and commitments that are no longer needed, economic or
recoverable in a competitive market. The amount of any losses the Company
may experience from stranded costs depends on the extent to which direct
competition is introduced to its business and the market price of energy.
Cost-based regulation traditionally results in the recognition of
revenues and expenses in accordance with rate commission orders which can
result in revenue and expense recognition in different time periods than for
enterprises that are not regulated. As a result, regulatory assets have been
recorded by regulated utility companies representing the deferral of costs
for recovery in future periods. The Company has approximately $2 billion in
regulatory assets. In order to maintain regulatory assets, the Company s
rates must be cost- based regulated. Management has reviewed the evidence
currently available and concluded that AEP continues to meet the requirements
to apply rate-regulated accounting standards. In the event a portion of the
Company s business no longer met these requirements, regulatory assets would
have to be written off for that portion of the business.
Whether future results of operations are adversely affected by losses or
write-offs also will depend on whether and how equitable recovery is
provided for by the applicable regulators. We intend to seek appropriate
recovery of any stranded costs and regulatory assets.
AEP s Response to Competitive Pressures
AEP has the financial strength, geographic reach,location and cost
structure to be an able competitor. However, no assurance can be given that
AEP can maintain this position in the future.
In 1995 AEP took steps to prepare for competition by realigning into
functional business units, expanding our marketing and customer service
efforts and proposing a plan for an orderly transition to retail competition.
Previously, AEP had proposed open access transmission rates.
In order to better position AEP for increasing competition among
electricity suppliers, we realigned from separate operating company
organizations to distinct Power Generation, Nuclear Generation, Energy
Delivery and Corporate Development operating units. We are realigning into
separate functional units in order (a) to facilitate the unbundling of
electric services to the extent required or permitted by the evolving
regulatory structure and (b) to operate more efficiently and effectively to
meet customers needs. The legal, financial, rate and regulatory
relationships of the subsidiary operating companies will not change.
To facilitate reliable, safe and efficient access for customers, AEP
supports the creation of an Independent System Operator (ISO) to operate a
multi-state transmission grid. Under AEP s proposal each electric company,
while retaining ownership, would place its portion of the transmission grid
under the management of the ISO who would be responsive to the needs of all
parties using the transmission grid. AEP also supports the evolution of a
Regional Power Exchange, which would establish a competitive marketplace for
generation. Generators and resellers of electricity would be permitted to
sell power into a spot market operated by the Regional Power Exchange. The
Regional Power Exchange would accept offers to buy and sell power and would
settle transactions based on the price at which supply and demand are
balanced. State regulators would continue to determine the terms, standards
and prices for the delivery service. Under our proposed plan regulators
would be authorized to establish distribution service charges which would
provide, as appropriate, for the recovery of stranded costs and regulatory
assets. These charges would be collected by electric companies from all new
and existing distribution services customers within a company s service
territory.
AEP has also offered access to its transmission grid at 142
interconnections under the same costs and terms available to AEP itself. The
unbundled transmission service for wholesale customers will provide AEP with
greater opportunities for transmission service revenues. Also, AEP has
responded to its retail customers by introducing new rate designs
(interruptible buy-through and real-time pricing) to provide lower cost-based
rates, to meet specific customers needs, and to offer customer choice.
AEP's proposals to pave the way for retail competition were issued to
enable the Company to participate in a meaningful way in the debate with
other interested parties so that we can build consensus and form coalitions
to shape the form of the future playing field. We plan to enhance
shareholder value by making AEP the supplier of choice. Our success will
depend on our ability to obtain a level playing field, improve and expand on
our energy sales and services and maintain and improve our relatively low
cost structure.
New Business Opportunities
We continue to seek and consider new business opportunities,
particularly those which permit the use of our expertise and core
competencies. In the non-rate-regulated environment, AEP offers consulting
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 addition, AEP is pursuing
investments in power generation, transmission and distribution projects. In
1995 AEP announced a strategic alliance with Cogentrix Energy and Zurn
Industries to pursue industrial power projects in the United States and
Canada. Cogentrix is one of the largest independent power producers in the
U.S., while Zurn is the largest turnkey engineer and constructor of both
biomass power plants and mid-sized gas turbine combined cycle plants in the
U.S.
AEP has been pursuing several other possible power generation,
transmission and distribution investment projects overseas. These investment
opportunities offer the potential for earning returns which exceed those of
the domestic rate-regulated operations. However, they also involve a higher
degree of risk which must be carefully considered and assessed. AEP may make
investments in these and other new business opportunities after management
carefully assesses the risks involved versus the potential for enhanced
shareholder value. Appropriate new business investments are part of AEP s
strategic plan for enhancing shareholder value and will be the full time
responsibility of our newly formed corporate development operating unit.
Affiliated Coal Cost
Fuel is 80% of the production cost of electricity. Although our fuel
costs have declined by one half in constant dollars since 1986, we must
continue to manage our coal costs to effectively compete. As long-term
contracts expire we are negotiating with suppliers to lower purchased coal
costs. We will continue to supplement our affiliated and long-term coal
supplies with spot market coal as favorable market conditions permit.
Approximately 13% of the coal we burn is supplied by affiliated mines; the
remainder is acquired under long-term contracts and in the spot market.
Efforts continue to reduce the cost of affiliated coal.
In recent years Ohio Power Company (OPCo) has been limited in its
recovery of the cost of coal produced by its affiliated mines in its Ohio
jurisdiction. Under the terms of a 1992 stipulation agreement a
predetermined price of $1.575 per million Btu s for coal burned at the Gavin
Plant was established effective December 1, 1994 for a 15-year period subject
to adjustment for inflation. A subsequent Settlement Agreement sets an
overall predetermined electric fuel component rate for OPCo at 1.465 cents
per kwh for the period June 1, 1995 through November 30, 1998. The Gavin
Plant predetermined price remains effective as escalated from the original
$1.575 per million Btu s. 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.
The predetermined prices provide OPCo with an opportunity to accelerate
recovery of its Ohio jurisdictional investment in and liabilities and closing
costs of the Company s Meigs, Muskingum and Windsor mining operations to the
extent the actual cost of coal burned at the Gavin Plant is less than the
predetermined prices. Based on the estimated future cost of coal at Gavin
Plant, we believe that OPCo should be able to recover under the terms of the
1992 stipulation agreement and in conjunction with the Settlement Agreement,
the Ohio jurisdictional portion of the cost of the affiliated mining
operations including mine closure costs. Management intends to seek from
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 $195 million after tax at December 31, 1995. The affiliated
Muskingum and Windsor mines may have to close by January 2000 as part of
compliance with Phase II requirements of the Clean Air Act Amendments of
1990. Should it become apparent that the costs of the affiliated mines
including future mine closure costs will not be recoverable, the mines could
be closed and results of operations adversely affected.
Nuclear Cost
The Company s only nuclear plant, the Donald C. Cook Nuclear Plant, has
recently achieved a superior rating from the Institute of Nuclear Power
Operations, a nuclear industry oversight group, and received improved
Nuclear Regulatory Commission (NRC) performance ratings. Refueling outage
costs have been reduced by $20 million compared to 1992 outage expense
levels. In an effort to continue to reduce costs and enhance organizational
efficiency, we announced in November that during the summer of 1996 we will
consolidate our Columbus-based nuclear management and support staff with the
plant staff at or near the Cook Nuclear Plant in Bridgman, Michigan.
The cost to operate and maintain the two-unit Cook Nuclear Plant is
impacted by federal laws and NRC requirements. 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 consumers of nuclear generated
electricity have paid $237 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 permanent repository for spent fuel. The federal
government has not made sufficient progress towards a permanent repository
and as long as there is a delay in the permanent storage repository for spent
nuclear fuel, the cost of a temporary or permanent repository will continue
to increase.
The cost to decommission the Cook Plant is affected by NRC regulations
and the DOE s SNF disposal program. Studies completed in 1994 estimate the
cost to decommission the plant and dispose of low-level nuclear waste
accumulation to range from $634 million to $988 million in 1993 dollars. The
decommissioning estimate could escalate due to uncertainty in the DOE s SNF
disposal program and the length of time that SNF may need to be stored at the
plant site delaying decommissioning. Presently we are recovering the
estimated cost of decommissioning the Cook Plant over its remaining life.
However, AEP s future results of operations and possibly its financial
condition could be adversely affected if the cost of spent nuclear fuel
disposal and decommissioning continues to increase and if for some reason
such costs cannot be recovered.
Environmental Concerns
Clean Air Act
To comply with the Clean Air Act Amendments of 1990 (CAAA) which
requires substantial reductions in sulfur dioxide and nitrogen oxides emitted
from electric generating plants, an AEP System wide least-cost compliance
plan was developed reflecting various methods of compliance. The corner
stone of the compliance strategy is the installation of flue gas
desulfurization systems (scrubbers) on the two-unit Gavin Plant which has
been responsible for about 25% of the System s total sulfur dioxide
emissions. By selecting scrubbers, the compliance plan allows the use of
Ohio high-sulfur coal at the Gavin Plant. The scrubbers for the Gavin units
are completed and operational. The PUCO approved the compliance plan as the
least cost compliance strategy and approved recovery of the compliance costs
under the terms of the Settlement Agreement.
Through the CAAA emission allowance program in which utilities are
authorized to emit a designated quantity of sulfur dioxide, measured in tons
per year, AEP, on a system wide or aggregate basis, will bank a substantial
number of Phase I allowances due to over compliance. To meet the stricter
standards of Phase II of the CAAA, AEP has the option to use banked Phase I
allowances, buy low sulfur com-pliance coal, purchase additional allowances
and/or build additional scrubbers. We also have the option to sell Phase I
allowances saved due to the installation of the scrubbers and the acquisition
of low sulfur coal.
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, the AEP generating
plants and transmission and distribution facilities have used asbestos,
polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous
materials. The AEP System is 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 legislation) addresses clean-up of hazardous substances
at disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the clean-up programs. As of year-end
1995, AEP companies 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 five other sites. There
are 11 additional sites for which AEP companies have received information
requests which could lead to PRP designation. Also, AEP companies have
received information requests with respect to four sites administered by
state authorities. AEP companies liability has been resolved for a number
of sites with no significant effect on results of operations. In those
instances where an AEP company has been named a PRP or defendant, the
disposal or recycling activity of the AEP company was in accordance with
applicable laws and regulations. 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 the AEP companies is often
unsubstantiated; the quantity of material the AEP companies disposed of at a
site was generally small; and the nature of the material AEP generally
disposed of was non-hazardous. Typically, an AEP subsidiary is 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, AEP s present estimates do not
anticipate material cleanup costs for identified sites for which AEP
subsidiaries 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.
Results of Operations
Earnings Increase
The 6% increase in net income to $530 million or $2.85 per share for
1995 from $500 million or $2.71 per share in 1994 was primarily due to
increased energy sales. Total sales of energy were 120.7 billion
kilowatthours in 1995 compared with 116.7 billion kilowatthours in 1994
reflecting increased usage and additional customers. Unseasonably warm
weather in the summer of 1995 and colder weather in the fourth quarter of
1995, compared with milder weather in the prior year s fourth quarter, were
the primary factors causing the increased usage. The positive earnings
impact of the increased sales was partly offset by the unfavorable effect of
$27 million in after-tax expenses related to severance pay charges.
In 1994 earnings increased 41% to $500 million or $2.71 per share from
$354 million or $1.92 per share in 1993. The increase was due to the effect
of a $145 million after-tax loss recorded in 1993 as a result of a
disallowance of a portion of the Company's Zimmer Plant investment. Without
the disallowance, 1993 earnings and earnings per share would have been $498
million and $2.70, respectively. Excluding the disallowance, 1994 earnings
increased slightly as compared to 1993 earnings predominately due to the
favorable effect of rate increases in several jurisdictions which were
heavily offset by the related amortization of Zimmer Plant deferrals and
increased operating expenses largely as a result of significant storm damage.
Revenues And Sales Increase
Operating revenues increased 3% in 1995 and more than 4% in 1994
reflecting increased energy usage by retail customers, growth in the number
of retail customers and the effects of rate increases. The change in
revenues is analyzed as follows:
Increase (Decrease)
From Previous Year
(Revenues in Millions) 1995 1994
Amount % Amount %
Retail:
Price Variance $ 46.5 $ 90.7
Volume Variance 173.0 53.8
Fuel Cost
Recoveries (22.9) 40.5
196.6 4.2 185.0 4.1
Wholesale:
Price Variance (39.3) 68.6
Volume Variance 10.8 (49.7)
Fuel Cost Recoveries (4.6) 8.1
(33.1)(4.6) 27.0 3.9
Other Operating Revenues 2.2 23.8
Total $165.7 3.0 $235.8 4.5
The increase in 1995 operating revenues resulted from a 4% increase in
energy sales to retail customers primarily due to increased usage and
continued growth in the number of customers in all retail customer classes.
Energy sales to residential customers, which is the most weather-sensitive
customer class, rose over 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 additional
customers, 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 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. Such sales
usually take place as a result of increased weather-related demand. The
increase in 1995 wholesale energy sales occurred during the last six months
of the year when the summer weather 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 competition.
Although demand and generation increased, fuel cost revenues declined in
1995 due to operation of the fuel clause mechanisms.
Operating revenues increased in 1994 primarily due to increased revenues
from retail customers reflecting retail rate increases in several
jurisdictions and an increase in retail energy sales and fuel cost
recoveries. A 2% increase in retail energy sales in 1994 was offset by a 7%
decline in wholesale sales resulting in a slight decline in net energy sales.
The 2% increase in retail energy sales in 1994 resulted from growth in
the number of residential, commercial and industrial customers served and
increased usage by industrial and commercial customers. Energy sales to
residential customers remained constant in 1994 due to mild weather during
most of the year.
Wholesale revenues increased 4% in 1994, on a 7% decrease in sales,
reflecting an increase in take-or-pay capacity charges to unaffiliated
utilities. Capacity charges are to reserve a specified quantity of AEP
System generating capacity and must be paid even when the energy is not
taken. The increase in capacity charges resulted from increased capacity
reserved under a long-term contract and short-term contracts with
unaffiliated utilities in the summer of 1994 because of a forced generating
unit outage. The increase in capacity reservation did not lead to a
corresponding increase in energy sold in 1994 due to mild weather throughout
most of 1994. The mild weather in 1994, combined with increased competition
in the wholesale market, reduced short-term wholesale sales for 1994.
Fuel cost recoveries increased in 1994 in both the retail and wholesale
jurisdictions resulting from increased fuel costs.
Future levels of short-term wholesale sales will be affected by the
competitive nature of the short-term energy market and other factors, such as
unaffiliated generating plant availability, the weather and the economy, all
of which are not generally within management's control. The Company's future
results of operations will be affected by its ability to make cost-effective
wholesale sales or, if such sales are reduced, the ability to raise retail
rates to reflect the loss of wholesale sales credits.
Future results of operations also will depend in part on the weather
since sales to residential and commercial customers are weather-sensitive.
Operating Expenses Increase
Changes in the components of operating expenses are shown in the table.
Increase (Decrease)
From Previous Year
(Dollars in Millions) 1995 1994
Amount % Amount %
Fuel and Purchased Power $(119.7) (6.9) $ 97.7 5.9
Other Operation 181.3 18.1 31.9 3.3
Maintenance (2.4) (0.5) 21.2 4.1
Depreciation and Amortization 20.8 3.6 41.5 7.8
Taxes Other Than Federal Income
Taxes (5.0) (1.0) 25.9 5.5
Federal Income Taxes 58.6 27.5 13.8 6.8
Total $ 133.6 2.9 $232.0 5.3
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
were increased utilization of low-cost nuclear generation in 1995; operation
of fuel clause mechanisms; and decreased energy purchases due to the mild
weather during the first half of 1995. Changes in fuel expense are generally
deferred pending recovery in various fuel recovery mechanisms, and as such
they generally do not affect earnings.
The increase in fuel and purchased power expense in 1994 was mainly the
result of increased utilization of coal-fired generation while the Cook Plant
nuclear units were unavailable during refueling and maintenance outages in
1994, and increased purchases of energy from unaffiliated utilities for pass-
through sales to other unaffiliated utilities.
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. Other operation
expense increased in 1994 as a result of regulatory-approved increases in
accruals and amortization, concurrent with rate recovery, of nuclear plant
decommissioning expense and certain low-income residential customers' payment
programs.
Maintenance expense increased in 1994 due to significant storm damage
caused by snow and ice storms during the first three months of 1994.
The increase in depreciation and amortization expense in 1994 was
primarily due to the court-ordered discontinuance of the Zimmer Plant phase-
in plan deferrals effective in February 1994 and the subsequent monthly
amortization of such costs as they were recovered in rates.
Taxes other than federal income tax expense rose in 1994 mainly due to
an increase in revenue-based gross receipts taxes of several states
reflecting the increase in 1994 revenues and an increase in generation-based
West Virginia taxes reflecting an increase in generation at West Virginia
power plants in 1994. Effective June 1995, the West Virginia tax is based on
generating capacity in West Virginia rather than on generation in West
Virginia which will result in a less volatile level of West Virginia taxes.
The increase in 1995 federal income tax expense attributable to
operations was primarily due to an increase in pre-tax operating income;
changes in certain book/tax differences accounted for on a flow-through basis
and the effects of accrual adjustments for prior year tax returns. The 1994
increase was mainly due to an increase in pre-tax operating income.
Deferred Carrying Charges and Nonoperating Income
The decrease in deferred Zimmer Plant carrying charges in 1995 and 1994
resulted from the cessation of deferrals commensurate with inclusion of the
full plant investment in rate base effective February 1, 1994 and the monthly
reduction in the deferred balance on which a return is earned. The deferred
balance declined due to its amortization to depreciation and amortization
expense commensurate with recovery through a rate surcharge.
The increase in other nonoperating income in 1995 and the decrease in
1994 was mainly due to the 1994 recordation of a provision for loss of $8.2
million after-tax on an investment. Also contributing to the 1994 decrease
was the effect of interest income recorded in March 1993 on tax refunds from
the Internal Revenue Service (IRS) in connection with the settlement of
audits of prior years' tax returns.
Interest Charges Increase
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 during the year. Refinancing
programs of several subsidiaries during the early part of 1994 and 1993
reduced the average interest rate on outstanding
long-term debt in 1994 as well as the levels of long-term debt causing the
decline in interest expense in 1994.
Common Dividend Remains Constant, Payout Ratio Decreases
The Company paid a quarterly dividend in 1995 of 60 cents a share
maintaining the annual dividend rate at $2.40 per share. The payout ratio
improved to 84% in 1995 from 89% in 1994. In 1993 the payout ratio was also
89% before the Zimmer disallowance.
Construction Spending Declining
Construction expenditures have been declining in recent years.
Management estimates cumulative construction expenditures for utility
operation to be $2 billion over the next three years with no major new plant
construction planned. Approximately 80% of the construction expenditures for
the next three years will be financed internally.
Liquidity and Capital Resources
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 preferred stock and with additional
capital contributions by the parent company. In 1995 short-term borrowing
increased by $48 million. At December 31, 1995, American Electric Power and
its subsidiaries had unused short-term lines of credit of $372 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. American Electric Power issued
1,400,000 shares of common stock in 1995 and 700,000 in 1994 through a
Dividend Reinvestment Program raising $49 million and $22 million,
respectively. As a result of the common stock issuance in 1995 and 1994 and
a reduction in long-term debt over the past several years, the common equity
to capitalization ratio has steadily improved. At December 31,1995 the ratio
increased to 43.1% from 42.1% at year end 1994 and has improved from 41.1% in
1992.
At December 31, 1995 the subsidiaries had outstanding $5.06 billion of
long-term debt and $671 million of preferred stock. The subsidiaries have
regulatory approval to issue up to $1.2 billion of long-term debt.
Management expects to use the proceeds of future long-term financing to
retire short-term debt, refinance maturing and other long-term debt, refund
cumulative preferred stock and fund construction expenditures.
Principal Operating Subsidiaries
Debt & Preferred Stock Coverage
Mortgage Preferred
December 31, 1995 Debt Stock
Appalachian Power Co. 3.47 1.78
Columbus Southern Power Co. 3.90 N/A
Indiana Michigan Power Co. 6.25 2.63
Kentucky Power Co. 2.86 N/A
Ohio Power Co. 6.17 3.04
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 an 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.
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.
Effects 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.
New Accounting Rules
The Financial Accounting Standards Board (FASB) issued a new accounting
standard, SFAS 121 Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of, in 1995 effective for 1996
accounting periods. The initial implementation of this new standard is not
expected to have a significant impact on the Company.
In 1996 the FASB issued an exposure draft Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets. This
document proposes that the present value of any decommissioning or other
closure or removal obligation 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 Company is
currently studying the impact of the proposed rules and evaluating its
potential impact.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in thousands - except per share amounts)
Year Ended December 31,
1995 1994 1993
OPERATING REVENUES $5,670,330 $5,504,670 $5,268,842
OPERATING EXPENSES:
Fuel and Purchased Power 1,625,531 1,745,245 1,647,573
Other Operation 1,184,158 1,002,822 970,916
Maintenance 541,825 544,312 523,062
Depreciation and Amortization 593,019 572,189 530,731
Taxes Other Than Federal Income Taxes 489,223 494,210 468,296
Federal Income Taxes 272,027 213,399 199,621
TOTAL OPERATING EXPENSES 4,705,783 4,572,177 4,340,199
OPERATING INCOME 964,547 932,493 928,643
NONOPERATING INCOME:
Deferred Zimmer Plant Carrying Charges (net of tax) 3,089 5,604 25,343
Other Nonoperating Income 17,115 5,881 21,229
TOTAL NONOPERATING INCOME 20,204 11,485 46,572
LOSS FROM ZIMMER PLANT DISALLOWANCE:
Disallowed Cost - - 159,067
Related Income Taxes - - (14,534)
NET ZIMMER LOSS - - 144,533
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 984,751 943,978 830,682
INTEREST CHARGES (net) 400,077 389,240 418,064
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES 54,771 54,726 58,849
NET INCOME $ 529,903 $ 500,012 $ 353,769
AVERAGE NUMBER OF SHARES OUTSTANDING 185,847 184,666 184,535
EARNINGS PER SHARE $2.85 $2.71 $1.92
CASH DIVIDENDS PAID PER SHARE $2.40 $2.40 $2.40
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(in thousands)
Year Ended December 31,
1995 1994 1993
RETAINED EARNINGS JANUARY 1 $1,325,581 $1,269,283 $1,358,800
NET INCOME 529,903 500,012 353,769
DEDUCTIONS:
Cash Dividends Declared 445,831 443,101 442,891
Other 8 613 395
RETAINED EARNINGS DECEMBER 31 $1,409,645 $1,325,581 $1,269,283
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,
1995 1994 1993
OPERATING ACTIVITIES:
Net Income $ 529,903 $ 500,012 $ 353,769
Adjustments for Noncash Items:
Depreciation and Amortization 578,003 561,188 555,436
Deferred Federal Income Taxes 11,916 (16,033) (62,186)
Deferred Investment Tax Credits (25,819) (31,275) (28,222)
Amortization of Operating Expenses and Carrying Charges (net) 53,479 16,022 2,997
Loss from Zimmer Plant Disallowance - - 159,067
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (71,804) 34,302 (15,641)
Fuel, Materials and Supplies 457 (1,627) 156,464
Accrued Utility Revenues (40,433) 2,419 18,994
Accounts Payable (31,044) (7,959) 47,018
Taxes Accrued 37,515 (26,521) 56,502
Other (net) 14,437 (52,803) 22,469
Net Cash Flows From Operating Activities 1,056,610 977,725 1,266,667
INVESTING ACTIVITIES:
Construction Expenditures (605,974) (643,457) (592,199)
Proceeds from Sale of Property and Other 20,567 49,802 26,669
Net Cash Flows Used For Investing Activities (585,407) (593,655) (565,530)
FINANCING ACTIVITIES:
Issuance of Common Stock 48,707 22,256 -
Issuance of Cumulative Preferred Stock - 88,787 321,168
Issuance of Long-term Debt 523,476 411,869 1,339,227
Retirement of Cumulative Preferred Stock (158,839) (35,949) (333,992)
Retirement of Long-term Debt (469,767) (445,636) (1,696,806)
Change in Short-term Debt (net) 48,140 38,009 25,822
Dividends Paid on Common Stock (445,831) (443,101) (442,891)
Net Cash Flows Used For Financing Activities (454,114) (363,765) (787,472)
Net Increase (Decrease) in Cash and Cash Equivalents 17,089 20,305 (86,335)
Cash and Cash Equivalents January 1 62,866 42,561 128,896
Cash and Cash Equivalents December 31 $ 79,955 $ 62,866 $ 42,561
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(In Thousands - Except Share Data)
December 31,
1995 1994
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 9,238,843 $ 9,172,766
Transmission 3,316,664 3,247,280
Distribution 4,184,251 3,966,442
General (including mining assets and nuclear fuel) 1,442,086 1,529,436
Construction Work in Progress 314,118 258,700
Total Electric Utility Plant 18,495,962 18,174,624
Accumulated Depreciation and Amortization 7,111,123 6,826,514
NET ELECTRIC UTILITY PLANT 11,384,839 11,348,110
OTHER PROPERTY AND INVESTMENTS 825,781 747,422
CURRENT ASSETS:
Cash and Cash Equivalents 79,955 62,866
Accounts Receivable:
Customers (less allowance for uncollectible accounts of
$5,430 in 1995 and $4,056 in 1994) 417,854 346,462
Miscellaneous 74,429 74,017
Fuel - at average cost 271,933 306,700
Materials and Supplies - at average cost 251,051 216,741
Accrued Utility Revenues 207,919 167,486
Prepayments and Other 98,717 94,786
TOTAL CURRENT ASSETS 1,401,858 1,269,058
REGULATORY ASSETS 1,979,446 2,040,997
DEFERRED CHARGES 310,377 333,169
TOTAL $15,902,301 $15,738,756
See Notes to Consolidated Financial Statements.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31,
1995 1994
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock-Par Value $6.50:
1995 1994
Shares Authorized. .300,000,000 300,000,000
Shares Issued. . . .195,634,992 194,234,992
(8,999,992 shares were held in treasury) $ 1,271,627 $ 1,262,527
Paid-in Capital 1,658,524 1,640,661
Retained Earnings 1,409,645 1,325,581
Total Common Shareholders' Equity 4,339,796 4,228,769
Cumulative Preferred Stocks of Subsidiaries:*
Not Subject to Mandatory Redemption 148,240 233,240
Subject to Mandatory Redemption 515,085 590,300
Long-term Debt* 4,920,329 4,686,648
TOTAL CAPITALIZATION 9,923,450 9,738,957
OTHER NONCURRENT LIABILITIES 884,707 794,478
CURRENT LIABILITIES:
Preferred Stock and Long-term Debt Due Within One Year* 144,597 293,756
Short-term Debt 365,125 316,985
Accounts Payable 220,142 251,186
Taxes Accrued 420,192 382,677
Interest Accrued 80,848 88,916
Obligations Under Capital Leases 89,692 93,252
Other 304,466 281,124
TOTAL CURRENT LIABILITIES 1,625,062 1,707,896
DEFERRED INCOME TAXES 2,656,651 2,657,062
DEFERRED INVESTMENT TAX CREDITS 430,041 456,043
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 249,875 259,152
DEFERRED CREDITS 132,515 125,168
CONTINGENCIES (Note 4)
TOTAL $15,902,301 $15,738,756
*See Accompanying Schedules on pages 34 - 35.
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.
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); and three active coal-mining companies. The five
largest utility subsidiaries, which pool their generating and transmission
facilities and operate them as an integrated system, are:
- - 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 substantially all 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.
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
four major business units which are managed centrally by AEPSC. The four
business units are Power Generation, Nuclear Generation, Energy Delivery and
Corporate Development.
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 and liabilities 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 6.91%, 6.59%, and 5.84% in 1995, 1994 and 1993,
respectively.
Depreciation, Depletion and Amortization - Depreciation is provided on a
straight-line basis over the estimated useful lives of property other than
coal-mining property and is calculated largely through the use of composite
rates by functional class as follows:
Functional Class Composite
of Property Annual Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-Conventional
and Pumped Storage 2.5% to 3.2%
Transmission 1.7% to 2.7%
Distribution 3.4% to 4.2%
General 2.0% 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 for coal rights and mine
development costs based on estimated recoverable tonnages at a current
average rate of $1.07 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 expires in 2000, CSPCo can sell
up to $50 million of undivided interests in designated pools of accounts
receivable and accrued utility revenues with limited recourse. As
collections reduce previously sold pools, interests in new pools are sold. At
December 31, 1995, 1994 and 1993, $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 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 the Company s Donald
C. Cook Nuclear Plant (Cook Plant) are deferred for amortization over the
period (generally eighteen months) beginning with the commencement of an
outage until 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, regulatory assets
and liabilities are recorded 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 deferred,
debited to 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.
Other Property and Investments - 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.
Excluding the decommissioning and spent nuclear fuel disposal trust
funds, other property and investments are stated at cost.
Reclassifications - Certain prior-period amounts were reclassified to conform
with current-period presentation.
2. Rate Matters:
Base Rate Activity - In March 1995 a Settlement Agreement was approved by the
Public Utilities Commission of Ohio (PUCO) that resolved a July 1994 base
rate case and a pending electric fuel component (EFC) proceeding. Under the
terms of the Settlement Agreement, base rates increased by $66 million
annually in March 1995 which includes recovery of the cost of the flue gas
desulfurization systems (scrubbers) installed at the Gavin Plant; the EFC
rate is fixed at 1.465 cents per kwh from June 1995 through November 1998;
OPCo is provided with the opportunity to recover its Ohio jurisdictional
share of its investment in and the liabilities and the future shut-down costs
of its affiliated mines as well as any fuel costs incurred above the fixed
rate; and OPCo may proceed with its Clean Air Act Amendments of 1990 (CAAA)
compliance plan as filed with the PUCO. The Settlement Agreement allows the
Company to continue to operate the affiliated Muskingum and Windsor mines.
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. (As discussed above the Settlement Agreement fixes the
EFC factor at 1.465 cents per kwh for the period June 1, 1995 through
November 30, 1998.) 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. The
stipulation agreement, in conjunction with the above-referenced Settlement
Agreement, provides OPCo with an opportunity to accelerate recovery of its
investment in and the liabilities and closing costs and any operating losses
incurred under the fixed EFC period of its affiliated mining operations
attributable to its Ohio jurisdiction to the extent the actual cost of coal
burned at the Gavin Plant is below the predetermined price.
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 will be
recovered under the terms of the predetermined price agreement. Management
intends to seek from 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 $195 million after tax at December 31, 1995.
The affiliated Muskingum and Windsor mines may have to close by January
2000 as part of compliance with Phase II requirements of the CAAA. The
Muskingum and/or Windsor mines could close prior to January 2000 depending on
the economics of continued operation under the terms of the above Settlement
Agreement. Unless future shutdown costs and/or the cost of affiliated coal
production of the Meigs, Muskingum and Windsor mines can be recovered,
results of operations would be adversely affected.
3. Effects of Regulation and Phase-In Plans:
The consolidated financial statements include assets and liabilities recorded
in accordance with regulatory actions to match expenses and revenues in cost-
based rates. The assets are expected to be recovered in future periods
through the rate-making process and the 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 regulatory assets would have to be written off for that
portion of the business.
Regulatory assets and liabilities are comprised of the following:
December 31,
1995 1994
(In Thousands)
Regulatory Assets:
Amounts Due From
Customers For
Future Income Taxes $1,446,485 $1,458,807
Rate Phase-in Plan
Deferrals 74,402 118,553
Unamortized Loss on
Reacquired Debt 109,551 108,777
Other 349,008 354,860
Total Regulatory Assets $1,979,446 $2,040,997
Regulatory Liabilities:
Deferred Investment
Tax Credits $430,041 $456,043
Other Regulatory
Liabilities* 86,347 76,468
Total Regulatory
Liabilities $516,388 $532,511
* Included in Deferred Credits on Consolidated Balance Sheets
The rate phase-in plan deferrals are applicable to the Zimmer Plant
Unit and the 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 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 under the phase-in
order.
As a result of the ruling, 1993 net income was reduced by $144.5
million after tax to reflect the disallowance and 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 1998. In 1995 and 1994 $28.5
million and $18.5 million, respectively, of net phase-in deferrals were
collected through the surcharge which reduced the deferrals from $93.9
million at December 31, 1993 to $75.4 million at December 31, 1994 and $46.9
million at December 31, 1995. In 1993 and 1992, $47.9 million and $46
million, respectively, were deferred under the phase-in plan. 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 deferrals. Unamortized deferred amounts under the
phase-in plans were $27.5 million and $43.2 million at December 31, 1995 and
1994, respectively. Amortization was $16 million in 1995, 1994 and 1993.
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 1996-1998 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 1,300 mw of capacity to
unaffiliated utilities. The Company has an obligation to deliver energy
under certain unit power agreements regardless of whether the unit capacity
is available. The power sales contracts expire from 1997 to 2010.
Nuclear Plant - I&M owns and operates the two-unit 2,110 mw Cook Plant under
licenses granted by a regulatory authority. 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 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 $40.9 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
$163 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 various factors including continued delays and uncertainties related to
the federal disposal program. At December 31, 1995, funds collected from
customers to eventually pay the pre-April 1983 fee and related earnings
including accrued interest approximated 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 $30 million in 1995,
$26 million in 1994 and $13 million in 1993. Decommissioning amounts
recovered from customers are deposited in external trusts. Trust fund
earnings increase the fund assets and the recorded liability and decrease the
amount to be recovered from ratepayers. At December 31, 1995 I&M has
recognized a decommissioning liability of $269 million.
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, debentures, 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, 1995, $230 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, 1995 and 1994 unused short-term bank lines of credit were
available in the amounts of $372 million and $558 million, respectively.
Commitment fees of approximately 1/8 of 1% of the unused short-term lines of
credit are paid each year to the banks to maintain the lines of credit.
Outstanding short-term debt consisted of:
December 31,
(Dollars In Thousands) 1995 1994
Balance Outstanding:
Notes Payable $128,425 $ 42,535
Commercial Paper 236,700 274,450
Total $365,125 $316,985
Year-End Weighted
Average Interest Rate:
Notes Payable 6.1% 6.2%
Commercial Paper 6.1% 6.3%
Total 6.1% 6.3%
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 trust fund contributions 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,
1995 1994 1993
(In Thousands)
Service Cost-Benefits
Earned During
the Year $ 30,400 $ 40,000 $ 37,100
Interest Cost on
Projected Benefit
Obligation 116,700 114,500 112,600
Actual Return on
Assets (416,800) (6,700) (150,000)
Net Amortization
and Deferral 281,800 (123,300) 24,700
Net AEP Pension
Plan Costs $ 12,100 $ 24,500 $ 24,400
AEP pension plan assets and actuarially computed benefit obligations are:
December 31,
1995 1994
(In Thousands)
AEP Pension Plan
Assets at
Fair Value (a) $1,805,300 $1,480,600
Actuarial Present Value
of Benefit Obligation:
Vested 1,321,600 1,130,000
Nonvested 147,400 120,700
Accumulated
Benefit Obligation 1,469,000 1,250,700
Effects of Salary
Progression 181,000 132,600
Projected Benefit
Obligation 1,650,000 1,383,300
Funded Status - AEP
Pension Plan Assets
in Excess of Projected
Benefit Obligation 155,300 97,300
Unrecognized Prior
Service Cost 147,000 160,800
Unrecognized Net Gain (295,200) (229,000)
Unrecognized Net
Transition Assets
(Being Amortized
Over 17 Years) (78,700) (88,600)
Accrued Net AEP
Pension Plan
Liability $ (71,600) $ (59,500)
(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,
1995 1994 1993
Discount Rate 7.25% 8.5% 7.0%
Average Rate of Increase in
Compensation Levels 3.2% 3.2% 3.2%
Expected Long-Term
Rate of Return on Plan Assets 9.0% 8.5% 9.0%
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
$18.8 million in 1995, $18.6 million in 1994 and $17.6 million in 1993.
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,
1995, the UMWA actuary estimates the OPCo coal-mining subsidiaries' share of
the UMWA pension plans unfunded vested liabilities was approximately $35
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 $1.4 million in
1995 and $1.6 million in both 1994 and 1993.
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 have at least 10 service years and are age 55 at retirement.
Postretirement medical benefits for OPCo's UMWA employees who have or
will retire after January 1, 1976 are the liability of the OPCo coal-mining
subsidiaries. They are eligible for postretirement medical and life
insurance benefits if they have at least 10 service years and are age 55 at
retirement. Non-active UMWA employees become eligible at age 55 if they have
had 20 service years.
Management has taken several measures to reduce its OPEB costs. First,
a Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB
benefits for all non-UMWA employees was established. In addition, to help
fund and reduce the future costs of OPEB benefits, a corporate owned life
insurance (COLI) program was implemented, except where restricted by state
law. The insurance policies have a substantial cash surrender value which is
recorded, net of equally substantial policy loans, in other property and
investments. Legislation was passed by Congress which would have
significantly reduced the tax benefits of a COLI program for the future. The
legislation containing this provision was vetoed by the President. At this
time it is uncertain if legislation repealing certain tax benefits from COLI
programs will be enacted. If enacted this legislation would negatively
impact the effectiveness of the COLI program as a funding and cost reduction
mechanism. For jurisdictions where OPEB costs are reflected in cost of
service, the funding policy is to make VEBA trust fund contributions equal to
the increase in OPEB costs resulting from the January 1993 implementation of
SFAS 106, "Employers Accounting for Postretirement Benefits Other Than
Pensions." These contributions include amounts collected from ratepayers and
the net earnings from the COLI program. For jurisdictions where recovery has
not been approved and rates are insufficient to absorb these additional
costs, the funding policy is to contribute cash generated by the COLI
program. Contribution to the VEBA trust fund, including amounts funded by
the COLI program, were $53 million in 1995, $29.5 million in 1994 and $21.5
million in 1993.
The utility subsidiaries received approval in several jurisdictions to
recover their increased OPEB costs resulting from the implementation of SFAS
106. For those jurisdictions where recovery has not been approved and rates
are insufficient to absorb these additional costs, the utility subsidiaries
received regulatory authority to defer the increased OPEB costs which are not
being currently recovered in rates. Future recovery of the deferrals and the
annual ongoing OPEB costs will be sought by the utility subsidiaries in their
next base rate filings. At December 31, 1995 and 1994, $24.6 million and
$28.5 million, respectively, of incremental OPEB costs were deferred.
Aggregate OPEB costs were computed as follows:
Year Ended December 31,
1995 1994 1993
(In Thousands)
Service Cost $ 13,500 $16,500 $15,700
Interest Cost on
Projected
Benefit Obligation 54,900 47,300 45,300
Net Amortization of
Transition Obligation 32,000 31,100 28,200
Return on Plan
Assets (25,400) 900 (1,000)
Net Amortization
and Deferral 16,800 (6,800) -
Net OPEB Costs $ 91,800 $89,000 $88,200
OPEB assets and actuarially computed benefit obligations are:
December 31,
1995 1994
(In Thousands)
Fair Market Value of
Plan Assets (a) $ 165,600 $ 87,200
Accumulated Postretirement
Benefit Obligation:
Active Employees
Fully Eligible for Benefits 59,200 41,200
Current Retirees 398,400 361,500
Other Active Employees 282,400 245,800
Total Benefit Obligation 740,000 648,500
Unfunded Benefit Obligation (574,400) (561,300)
Unrecognized Net Loss 48,500 8,900
Unrecognized Net Transition
Obligation Being
Amortized Over 20 Years 485,600 517,700
Accrued Net OPEB
Liability $ (40,300) $ (34,700)
(a) Plan assets consist of cash surrender value of life insurance contracts
on certain employees owned by the trust and short-term tax exempt municipal
bonds.
Assumptions used to determine OPEB's funded status were:
December 31,
1995 1994 1993
Discount Rate 7.25% 8.5 % 7.0 %
Expected Long-Term Rate
of Return on Plan Assets 8.75% 8.25% 8.75%
Initial Medical Cost Trend Rate 8.0 % 8.0 % 8.0 %
Ultimate Medical Cost Trend Rate 4.5 % 5.25% 4.25%
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 1995 OPEB
cost for all employees, both non-UMWA and UMWA, would increase by $9 million
and the accumulated benefit obligations would increase by $78 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 $2.8 million in 1995, $3.1 million in 1994 and
$3.8 million in 1993.
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 $7.9
million in 1995, $6.9 million in 1994 and $10 million in 1993. The Black
Lung Trust had excess funds at December 31, 1995, 1994 and 1993 of $13
million, $16 million and $18 million, respectively.
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 primarily of long-term tax-exempt
municipal bonds.
At December 31, 1995 and 1994 the fair values of the trust investments
were $434 million and $353 million, respectively. Accumulated gross
unrealized holding gains and losses were $19.1 million and $1.0 million,
respectively, at December 31, 1995. The change in market value was a $24.9
million net holding gain in 1995 and a $27.1 million net holding loss in
1994.
The trust investments' cost basis by security type were:
December 31,
1995 1994
(In Thousands)
Treasury Bonds $ 14,963 $ 997
Tax-Exempt Bonds 336,073 332,098
Equity Securities 24,101 1,665
Cash, Cash Equivalents and Interest Accrued 40,356 25,304
Total $415,493 $360,064
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. Proceeds from sales and maturities of securities of $20.1
million during 1994 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, 1995, the year of maturity of trust fund investments
other than equity securities, was:
(In Thousands)
1996 $ 55,748
1997 - 2000 96,882
2001 - 2005 162,563
After 2005 76,199
Total $391,392
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 $544 million and $537 million and for long-term
debt were $5.3 billion and $4.7 billion at December 31, 1995 and 1994,
respectively. The carrying amounts for preferred stock subject to mandatory
redemption were $523 million and $590 million and for long-term debt were
$5.1 billion and $5.0 billion at December 31, 1995 and 1994, 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,
1995 1994 1993
(In Thousands)
Charged (Credited) to Operating Expenses (net):
Current $265,313 $240,655 $270,318
Deferred 22,990 (10,177) (53,462)
Deferred Investment Tax Credits (16,276) (17,079) (17,235)
Total 272,027 213,399 199,621
Charged (Credited) to Nonoperating Income (net):
Current 11,325 (2,907) 8,727
Deferred (11,074) (5,856) 4,603
Deferred Investment Tax Credits (9,543) (14,196) (9,780)
Total (9,292) (22,959) 3,550
Credited to Loss from Zimmer Plant Disallowance (net):
Deferred - - (13,327)
Deferred Investment Tax Credits - - (1,207)
Total - - (14,534)
Total Federal Income Tax as Reported $262,735 $190,440 $188,637
The following is a reconciliation of the difference between the amount
of federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income
taxes reported.
Year Ended December 31,
1995 1994 1993
(In Thousands)
Income Before Preferred Stock
Dividend Requirements of Subsidiaries $584,674 $554,738 $412,618
Federal Income Taxes 262,735 190,440 188,637
Pre-Tax Book Income $847,409 $745,178 $601,255
Federal Income Tax on Pre-Tax Book
Income at Statutory Rate (35%) $296,593 $260,812 $210,439
Increase (Decrease) in Federal Income Tax
Resulting from the Following Items:
Depreciation 46,453 31,212 27,554
Removal Costs (14,640) (13,818) (17,730)
Corporate Owned Life Insurance (25,506) (22,970) (27,310)
Investment Tax Credits (net) (26,179) (31,273) (28,218)
Zimmer Plant Disallowance - - 42,346
Federal Income Tax Accrual Adjustments - (16,100) (6,500)
Other (13,986) (17,423) (11,944)
Total Federal Income Taxes as Reported $262,735 $190,440 $188,637
Effective Federal Income Tax Rate 31.0% 25.6% 31.4%
The following tables show the elements of the net deferred tax liability and
the significant temporary differences:
December 31,
1995 1994
(In Thousands)
Deferred Tax Assets $ 723,196 $ 657,298
Deferred Tax Liabilities (3,379,847) (3,314,360)
Net Deferred Tax Liabilities $(2,656,651) $(2,657,062)
Property Related Temporary Differences $(2,139,387) $(2,098,304)
Amounts Due From Customers For
Future Federal Income Taxes (442,311) (444,305)
Deferred State Income Taxes (183,981) (183,987)
All Other (net) 109,028 69,534
Total Net Deferred Tax Liabilities $(2,656,651) $(2,657,062)
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. 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,
1995 1994 1993
(In Thousands)
Operating Leases $259,877 $233,805 $243,190
Amortization of Capital Leases 101,068 79,116 84,226
Interest on Capital Leases 27,542 23,280 23,839
Total Rental Payments $388,487 $336,201 $351,255
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1995 1994
(In Thousands)
ELECTRIC UTILITY PLANT:
Production $ 44,849 $ 44,683
Transmission 7 38
Distribution 14,753 14,717
General:
Nuclear Fuel (net of amortization) 69,442 89,478
Mining Plant and Other 424,952 403,038
Total Electric Utility Plant 554,003 551,954
Accumulated Amortization 179,952 173,641
Net Electric Utility Plant 374,051 378,313
OTHER PROPERTY 34,536 24,724
Accumulated Amortization 3,994 2,838
Net Other Property 30,542 21,886
Net Property under Capital Leases $404,593 $400,199
Obligations under Capital Leases $404,593 $400,199
Less Portion Due Within One Year 89,692 93,252
Noncurrent Capital Lease Liability $314,901 $306,947
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,
1995:
Noncancelable
Capital Operating
Leases Leases
(In Thousands)
1996 $ 86,495 $ 244,228
1997 72,576 239,800
1998 56,165 231,449
1999 47,531 229,296
2000 39,547 227,506
Later Years 156,895 4,092,193
Total Future Minimum Lease Rentals 459,209(a) $5,264,472
Less Estimated Interest Element 124,058
Estimated Present Value of Future Minimum
Lease Rentals 335,151
Unamortized Nuclear Fuel 69,442
Total $404,593
(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,
1995 1994 1993
(In Thousands)
Purchased Power -
Ohio Valley Electric Corp. (44.2% owned by AEP) $10,546 $5,755 $19,253
Cash was paid for:
Interest (net of capitalized amounts) $395,169 $379,361 $421,060
Income Taxes $273,671 $312,233 $245,350
Noncash Acquisitions under Capital Leases were $106,256 $227,055 $80,220
12. CAPITAL STOCKS AND PAID-IN CAPITAL:
Changes in capital stocks and paid-in capital during the period January
1, 1993 through December 31, 1995 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, 1993 193,534,992 10,761,675 $1,257,977 $1,628,394 $ 534,978 $233,509
Issues - 3,250,000 - - - 325,000
Retirements and
Other - (6,323,907) - (4,218) (266,738) (57,972)
December 31, 1993 193,534,992 7,687,768 1,257,977 1,624,176 268,240 500,537
Issues 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
Issues 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
(a) Includes 8,999,992 shares of treasury stock.
(b) Including portion due within one year.
13. Unaudited Quarterly Financial Information:
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
Quarterly Periods Ended
1994
March 31 June 30 Sept. 30 Dec. 31
(In Thousands - Except
Per Share Amounts)
Operating Revenues $1,488,185 $1,348,563 $1,385,278 $1,282,644
Operating Income 257,517 219,496 247,015 208,465
Net Income 152,954 103,793 139,826 103,439
Earnings per Share 0.83 0.56 0.76 0.56
Fourth quarter 1994 net income includes favorable federal income tax accrual adjustments of $16.1 million
related to the resolution of various issues with the IRS.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
SCHEDULE OF CONSOLIDATED CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
December 31, 1995
Call
Price per Shares Shares Amount (in
Share (a) Authorized(b) Outstanding thousands)
Not Subject to Mandatory Redemption:
4.08% - 4.56% $102-$110 932,403 932,403 $ 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 (c):
4.50% $102 19,625 2,348 $ 235
5.90% - 5.92% (d) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000
7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000
9.50% (g) 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
_____________________________________________
December 31, 1994
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% - 7.76% $101.85-$102.26 1,250,000 1,250,000 125,000
8.04% $102.58 150,000 150,000 15,000
Total Not Subject to Mandatory
Redemption $233,240
Subject to Mandatory Redemption (c):
4.50% $102 19,625 3,848 $ 385
5.90% - 5.92% (d) 1,950,000 1,950,000 195,000
6.02% - 6-7/8% (e) 1,950,000 1,950,000 195,000
7% - 7-7/8% $107.80-$107.88(f) 1,250,000 1,250,000 125,000
9.50% (g) 750,000 750,000 75,000
Total Subject to Mandatory
Redemption (h) 590,385
Less Portion Due Within One Year 85
Long-term Portion $590,300
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
(December 31, 1995 price is shown) plus accrued dividends. The involuntary liquidation
preference is $100 per share for all outstanding shares.(b) As of December 31, 1995 the
subsidiaries had 4,255,000, 22,200,000 and 5,547,652 shares of $100, $25 and no par value
preferred stock, respectively, that were authorized but unissued.
(c) 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.
(d) Redemption is prohibited prior to 2003; after that the call price is $100 per share.
(e) Redemption is prohibited prior to 2000; after that the call price is $100 per share.
(f) Redemption is restricted prior to 1997.
(g) On February 1, 1996 the outstanding balance of 75,000 shares was redeemed at $100 per share.
(h) The sinking fund provisions of the series subject to mandatory redemption aggregate
$7,650,000, $84,800, $5,000,000, $5,000,000 and $16,000,000 in 1996, 1997, 1998, 1999 and 2000, respectively.
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, 1995 1995 1994 1995 1994
(in thousands)
FIRST MORTGAGE BONDS
1995-1999 7.05% 5%-9.15% 5%-9.15% $ 496,866 $ 526,866
2001-2005 7.28% 6%-9.31% 6%-9.31% 1,530,020 1,450,020
2019-2025 8.26% 7.10%-9-7/8% 7.10%-9-7/8% 1,473,127 1,540,661
INSTALLMENT PURCHASE CONTRACTS(a)
1995-2002 5.65% 5%-7-1/4% 6%-7-1/4% 209,500 174,500
2007-2025 6.45% 5.45%-7-7/8% 5.45%-9-3/8% 756,745 811,745
NOTES PAYABLE(b)
1995-2008 7.87% 5.29%-10.78% 5.29%-10.78% 221,000 313,000
DEBENTURES
1996 - 1999(c) 6.40% 5-1/8%-7-7/8% 5-1/8%-7-7/8% 30,759 30,759
2025 8.35% 8.16%-8.72% - 200,000 -
OTHER LONG-TERM DEBT(d) 172,403 163,896
Unamortized Discount (net) (33,144) (31,128)
Total Long-term Debt
Outstanding (e) 5,057,276 4,980,319
Less Portion Due Within One Year 136,947 293,671
Long-term Portion $4,920,329 $4,686,648
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 the demand of the owners 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 will be reacquired by March 1, 1996.
(d) Other long-term debt consist 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, 1995 is payable as follows:
Principal Amount (in thousands)
1996 $ 136,947
1997 86,933
1998 269,266
1999 185,673
2000 168,648
Later Years 4,242,953
Total $5,090,420
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, 1995 and
1994, and the related consolidated statements of income, retained earnings,
and cash flows for each of the three years in the period ended December 31,
1995. 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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 1995 in conformity with generally accepted
accounting principles.
Deloitte & Touche LLP
Columbus, Ohio
February 27, 1996