Selected Consolidated Financial Data
Year Ended December 31,
1993 1992 1991 1990 1989
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,708,577 $1,691,597 $1,679,168 $1,778,824 $1,835,934
Operating Expenses 1,440,390 1,439,826 1,412,961 1,510,112 1,534,868
Operating Income 268,187 251,771 266,207 268,712 301,066
Nonoperating Income 18,075 22,391 7,513 11,146 10,586
Income Before Interest Charges 286,262 274,162 273,720 279,858 311,652
Interest Charges 100,492 113,609 107,618 99,868 103,474
Net Income 185,770 160,553 166,102 179,990 208,178
Preferred Stock Dividend
Requirements 16,990 17,115 17,112 17,804 18,083
Earnings Applicable to Common
Stock $ 168,780 $ 143,438 $ 148,990 $ 162,186 $ 190,095
December 31,
1993 1992 1991 1990 1989
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,802,327 $4,733,782 $4,761,356 $4,624,077 $4,511,533
Accumulated Depreciation and
Amortization 1,992,082 1,916,011 1,871,711 1,776,299 1,688,983
Net Electric Utility Plant $2,810,245 $2,817,771 $2,889,645 $2,847,778 $2,822,550
Regulatory Assets (a) $ 645,372 $ 132,020 $ 170,645 $ 165,731 $ 184,292
Total Assets $4,116,305 $3,722,354 $3,714,425 $3,613,761 $3,532,175
Common Stock and Paid-in
Capital $ 784,301 $ 786,108 $ 786,108 $ 786,110 $ 786,203
Retained Earnings 474,500 445,955 436,689 420,755 400,635
Total Common Shareowner's
Equity $1,258,801 $1,232,063 $1,222,797 $1,206,865 $1,186,838
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 126,240 $ 232,978 $ 232,978 $ 233,133 $ 242,095
Subject to Mandatory
Redemption (b) 115,000 - - - -
Total Cumulative Preferred
Stock $ 241,240 $ 232,978 $ 232,978 $ 233,133 $ 242,095
Long-term Debt (b) $1,194,483 $1,366,221 $1,240,140 $1,198,314 $1,158,301
Obligations Under Capital
Leases (b) $ 97,329 $ 96,168 $ 112,802 $ 107,207 $ 110,862
Total Capitalization and
Liabilities $4,116,305 $3,722,354 $3,714,425 $3,613,761 $3,532,175
(a) Effective January 1, 1993 a new accounting standard Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes, was
adopted resulting in an increase in regulatory assets. (See Note 1 of
the Notes to Consolidated Financial Statements).
(b) Including portion due within one year.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Net Income Increased
Net income increased 16% to $185.8 million in 1993 due mainly to improved
retail sales reflecting a return to normal weather, an improvement in the
industrial economy in the Company's service territory and decreased interest
expense due to refinancings and decreased borrowings. In 1992 net income
decreased 3% due to unseasonably mild weather, price competition in the
short-term wholesale energy market, and increased interest charges reflecting
the issuance of additional long-term debt.
Outlook
The electric utility industry is expected to undergo significant changes
for the remainder of the decade because of increasing competition in the
generation and sale of electricity and increasing energy flows resulting from
open transmission access. Although management believes that the Company is
well positioned, as a low cost producer, to compete, efforts will continue to
increase effectiveness and productivity through the restructuring and
combination of operations with an affiliate, Columbus Southern Power Company.
These efforts have eliminated over 200 positions of the Company and closed
duplicate and less productive distribution facilities.
The Company faces additional challenges recovering the cost of affiliated
coal-mining operations including the cost of eventual mine closures and
reclamation, the Clean Air Act Amendments of 1990 and other environmental
concerns that could affect future financial performance and possibly the
ability to meet financial obligations and commitments. While management
believes the Company is equipped to meet these challenges, future financial
performance is heavily dependent on the ability to obtain favorable rate-
making treatment to recover on a timely basis the Company's costs of service.
Future results of operations will also be affected by the continued
economic health of the Company's service territory, the weather, competition
for wholesale sales, the market price for unaffiliated coal vs. the cost
of affiliated coal, new environmental laws and regulations and the rate-
making policies of the Company's regulators. Many of these factors are not
generally within management's direct control yet every effort will be made to
work with regulators, government officials, and current and prospective
customers to positively influence these critical factors and to take
advantage of the opportunities increased competition will bring.
Operating Revenues and Energy Sales
The slight increase in revenues in 1993 and 1992 was predominantly
attributable to increased retail sales in 1993 and increased wholesale sales
in 1992. The change in revenues in 1993 and 1992 can be analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1993 1992
Amount % Amount %
Retail:
Price variance $ (6.6) $(10.7)
Volume variance 41.1 4.9
Fuel Cost Recoveries 7.2 7.0
41.7 3.5 1.2 0.1
Wholesale:
Price variance 13.4 (12.9)
Volume variance (38.2) 25.7
Fuel Cost Recoveries (0.7) (2.2)
(25.5) (5.5) 10.6 2.3
Other Operating Revenues 0.8 0.6
Total $ 17.0 1.0 $ 12.4 0.7
The increase in retail revenues in 1993 reflects a return to normal hot
summer weather, which increased sales to residential and commercial
customers, and continued improvement in industrial sales. The increase in
industrial sales was mainly due to improved business conditions which in-
creased the number of industrial customers and the sales to existing
customers.
Wholesale sales decreased in 1993 and increased in 1992 mainly as a result
of changes in demand from the American Electric Power System Power Pool
(Power Pool). The variation in deliveries to the Power Pool was mainly due
to the nuclear generating units of an affiliated company being out of service
for refueling and maintenance in 1992. Energy sales to the Power Pool are
priced to compensate the supplying Power Pool member for its out-of-pocket
costs. Partially offsetting the change in Power Pool sales in both years
were energy sales to unaffiliated utilities which increased in 1993 and
decreased in 1992. The upturn in 1993 sales to unaffiliated utilities was
mainly in short-term sales and was due to decreased availability of
unaffiliated generating units combined with the return to normal hot summer
weather. The decline in sales to unaffiliated utilities in 1992 was caused
by price competition in the wholesale electric energy market, increased
availability of unaffiliated utilities' generating units, the expiration of
certain wholesale contracts, the sluggish economy and mild weather.
Efforts to improve short-term wholesale sales are affected by the highly
competitive nature of the short-term energy market and other factors, such as
unaffiliated generating plant availability, the weather and the economy, that
are not generally within management's control. Future results of operations
will be affected by management's ability to make cost-effective wholesale
sales or, if such sales are reduced, the ability to timely raise retail
rates.
Operating Expenses
Operating expenses were relatively unchanged in 1993 after increasing 2% in
1992. Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1993 1992
Amount % Amount %
Fuel $(22.1) (3.3) $ 26.0 4.1
Purchased Power 10.2 16.7 (15.4) (20.2)
Other Operation 9.3 4.4 9.5 4.7
Maintenance (14.4) (9.3) 5.8 3.9
Depreciation and
Amortization 4.2 3.4 2.4 2.0
Taxes Other Than Federal
Income Taxes 8.5 5.3 16.6 11.6
Federal Income Taxes 4.9 7.5 (18.0) (21.4)
Total Operating
Expenses $ 0.6 - $ 26.9 1.9
In 1993 fuel expense decreased due to a lower average cost of fuel consumed
and decreased generation reflecting reduced Power Pool demand. The increase
in fuel expense in 1992 was caused by increased generation to meet the
increased demand from the Power Pool and industrial customers, partly offset
by a lower average cost of fuel consumed.
Purchased power expense increased significantly in 1993 mainly due to an
increase in purchases from the Power Pool to meet the increased demand for
retail power. The decrease in purchased power in 1992 resulted mainly from a
decline in power purchased from unaffiliated utilities for pass-through sales
to other unaffiliated utilities and a decrease in Power Pool energy
purchases.
Reductions in scheduled power plant maintenance accounted for the decrease
in maintenance expense in 1993.
The increase in taxes other than federal income taxes in 1993 was mainly in
West Virginia business and occupation taxes and resulted from increased
generation at plants located in West Virginia. In 1992 taxes other than
federal income taxes increased due to the effect of favorable prior year
accrual adjustments recorded in 1991 associated with the closing of prior
years' business and occupation tax returns.
In 1993 federal income tax expense attributable to operations increased
primarily due to increased pre-tax operating income, offset in part by
unfavorable accrual adjustments recorded in 1992 for prior years' federal
income tax returns. The decrease in 1992 federal income tax expense
attributable to operations was due primarily to a decrease in pre-tax
operating income.
Nonoperating Income and Interest Charges
Nonoperating income declined in 1993 and increased significantly in 1992
mainly because of interest income recorded in 1992 on tax refunds from the
Internal Revenue Service in connection with the settlement of audits of prior
years' tax returns. Interest income was also recorded in 1992 on receivables
from customers for the collection of prior years' fuel costs resulting from
the favorable resolution of litigation regarding Federal Energy Regulatory
Commission (FERC) ordered revenue refunds which the Company made in 1988.
Interest charges decreased in 1993 after increasing in 1992. Debt
refinancings and retirements reduced interest in 1993. Interest charges in-
creased in 1992 largely due to the issuance of additional first mortgage
bonds used to repay short-term debt. Management intends to continue, where
possible, to refinance higher cost securities to take advantage of favorable
market interest rates.
Regulatory Assets and Deferred Tax Liabilities Increase
The Company prospectively adopted a new accounting standard for income
taxes on January 1, 1993. The new standard required, among other things,
that regulated entities record deferred tax liabilities on temporary
differences previously flowed-through for rate-making and book accounting.
Where rate-making provides for flow-through treatment, corresponding
regulatory assets were recorded. As a result total assets and liabilities
increased significantly while net income increased by only $3.6 million.
Construction Spending
Total plant and property additions decreased to $197 million in 1993 from
$222 million in 1992. Management estimates construction expenditures for the
next three years to be $484 million including expenditures necessary to meet
the requirements of the Clean Air Act Amendments of 1990. These amounts
exclude flue gas desulfurization systems (scrubbers) at the Company's two-
unit 2,600 megawatt (mw) Gavin Plant which are being constructed by an
unaffiliated entity and which will be leased under an operating lease. Funds
for construction of new facilities and improvement of existing facilities
come from a combination of internally generated funds, short-term and long-
term borrowings and equity investments by the Company's parent, American
Electric Power Company, Inc. (AEP Co., Inc.). Approximately 86% of the
construction expenditures for the next three years will be financed
internally with the remainder financed externally.
Debt and Preferred Stock Financing
The Company generally issues short-term debt to provide for interim
financing of capital expenditures that exceed internally generated funds. At
December 31, 1993, unused short-term lines of credit of $537 million shared
with other AEP System companies were available. Short-term borrowings in-
creased by $40 million in 1993. Regulatory provisions limit short-term
borrowing to $200 million; however, this limit may be raised. Outstanding
short-term debt is reduced periodically through the issuance of long-term
debt and preferred stock and through equity capital contributions by AEP Co.,
Inc.
The Company received or has requested regulatory approval to issue up to
$85 million of long-term debt and $85 million of preferred stock. Management
expects to use the resultant proceeds to retire short-term debt, refinance
higher cost and maturing long-term debt, refund cumulative preferred stock
and fund construction expenditures.
Unless the Company meets certain earnings or coverage tests, additional
long-term debt or preferred stock cannot be issued. In order to issue
certain long-term debt without refunding an equal amount of existing debt,
pre-tax earnings must be equal to at least twice the annual interest charges
on long-term debt after giving effect to the new debt. To issue additional
preferred stock, after-tax gross income must be at least equal to one and
one-half times annual interest and preferred stock dividend requirements
after giving effect to the new preferred stock. The Company presently
exceeds these minimum coverage requirements. At December 31, 1993, the long-
term debt and preferred stock coverage ratios were 4.65 and 2.88,
respectively.
Recently a major credit rating agency reevaluated the credit worthiness of
companies in the electric utility industry based on perceived risk from
deregulation, increased competition, reduced load growth, escalating nuclear
plant costs and environmental concerns. The agency lowered its ratings
outlook for approximately one-third of the companies but not for Ohio Power
which was regarded by the agency as being relatively well positioned to meet
future competitive challenges.
Competition
Since 1990 the short-term wholesale energy market has been extremely
competitive. With the passage of the Energy Policy Act of 1992, which
provides for greater ease of wholesale transmission access and reduces
certain regulatory restrictions for independent power producers (IPPs),
competition is expected to increase in the long-term wholesale market and in
the construction of new generating capacity. For example, IPPs are no longer
required to find an industrial host to utilize the steam by-product from the
generation of electricity to build a generating unit and avoid regulation
under the Public Utility Holding Company Act of 1935 (1935 Act). The Energy
Policy Act also exempts IPPs from requirements under the 1935 Act which,
among other things, permit IPPs to use greater amounts of lower cost debt
which may reduce overall cost of capital. Thus IPPs may have a competitive
advantage. Although the Energy Policy Act specifically prohibits FERC from
ordering retail transmission access, the states can do so and many believe
that the next logical step will be the extension of competition for existing
industrial customers which will present both opportunities and challenges for
the Company.
Although management believes that the Company is well positioned to compete
in this evolving competitive market because of its technical skills and
expertise and its position as a low cost producer, we intend to continue to
examine ways to improve the Company's competitive position. Efforts to
improve operations and reduce costs will continue in order to maintain and
enhance our position as a low cost producer.
Although management may have opportunities to improve shareholder value
through increased competition as a result of open transmission access and
other provisions of the Energy Policy Act of 1992, there is risk and
uncertainty, especially for retail ratepayers and shareholders, regarding
reliability of future transmission service and fair compensation for use of
the Company's extensive high voltage transmission facilities. Management's
goal is to ensure that, to the extent the Company's facilities are used by
others, there is fair and appropriate compensation.
Environmental Concerns and Cost Pressures
Clean Air Act
The Clean Air Act Amendments of 1990 (CAAA) require, among other things,
substantial reductions in sulfur dioxide and nitrogen oxides emitted from
electric generating plants. The AEP Systemwide compliance plan employs
various methods of compliance. The cornerstone of its least-cost strategy is
the installation of scrubbers on the Company's two-unit 2,600 mw Gavin Plant
which is responsible for about 25% of the System's total sulfur dioxide
emissions. The use of scrubbers allows Ohio high-sulfur coal including the
Company's affiliated Meigs mine coal to continue to be burned at the Gavin
Plant. The scrubbers will be leased from an unaffiliated company and are to
be completed by early 1995.
The Public Utilities Commission of Ohio (PUCO) approved the compliance plan
as a least-cost compliance strategy in November 1992. As a result, under
Ohio law the plan is deemed prudent for subsequent PUCO rate proceedings. In
connection with the approval of the plan, the PUCO approved a stipulation
agreement which limits the maximum recoverable cost of the scrubbers to $815
million and imposes a predetermined price for coal burned at certain Company
power plants including the Gavin Plant (discussed below under "Fuel Costs").
The scrubbers are currently estimated to cost at least 10% less than the $815
million cost cap. Based on the estimated cost to complete the scrubbers and
current estimates for Gavin fuel costs, management believes that the two
limits should not result in losses.
Under the approved plan, fuel switching will be the compliance method for
the Company's Muskingum River Plant generating units in 1995 and 2000 and the
Cardinal Plant units in 2000. The plants are currently supplied by wholly-
owned high-sulfur coal-mining subsidiaries, operating the Muskingum and
Windsor mines. Consequently, these affiliated mining operations could shut
down resulting in substantial costs to be recovered. Shutdown costs for the
Muskingum and Windsor mines include investments in the mines, leased asset
buy-outs, reclamation and employee benefits and are estimated to be
approximately $250 million at December 31, 1993.
Management intends to seek recovery through increased rates of the cost of
compliance with the CAAA. Since the Company will incur substantial
compliance costs, management is planning to file for a retail rate increase
in Ohio in 1994. While there can be no assurance that regulators will
provide for recovery of all such costs on a timely basis, every effort is
being made to work with the PUCO to obtain timely recovery of the compliance
cost. The cost of compliance with the CAAA, including potential mine closure
costs, will have an adverse effect on results of operations and financial
condition if not recovered from customers or through asset dispositions.
Global Warming
Concern about global climate change, or "the greenhouse effect" has been
the focus of intensive debate within the United States and around the world.
Much of the uncertainty about what effects greenhouse gas concentrations will
have on the global climate results from a myriad of factors that affect
climate. Based on the terms of a 1992 United Nations treaty that pledged the
United States to reduce greenhouse gas emissions, the Clinton Administration
developed a voluntary plan to reduce, by the year 2000, greenhouse gas
emissions to 1990 levels. The AEP System supports the plan and will work
with the U.S. Department of Energy and other electric utility companies to
formulate a cost effective framework for limiting future greenhouse gas
emissions.
The AEP System strongly supports a policy of proactive environmental
stewardship, whereby actions are taken that make economic and environmental
sense on their own merits, irrespective of the uncertain threat of global
climate change. To reduce emissions, we support energy conservation
programs, development of more efficient generation and end use technologies,
and forest management activities because they are cost effective and bring
long-term benefits to our service area. Should significant new measures to
control the burning of coal be enacted, they could affect the Company's
competitiveness and, if not recovered from customers, adversely impact
results of operations and financial condition.
EMF
Whether electric and magnetic fields (EMF) from transmission and
distribution facilities adversely affect the public health is being
extensively researched. Management continues to support EMF research to help
determine the extent, if any, to which EMF may adversely impact public
health. However, our concern is that new laws imposing EMF limits may be
passed or new regulations promulgated without sufficient scientific study and
evidence to support them. As long as there is uncertainty about EMF, we will
have difficulty finding acceptable sites for our transmission facilities,
which could hamper economic growth within our service area. If the present
energy delivery system must be changed because of EMF concerns, or if the
courts conclude that EMF exposure harms individuals and that utilities are
liable for damages, then results of operations and financial condition could
be adversely affected, unless the costs can be recovered from customers.
Hazardous Material
By-products from the generation of electricity include materials such as
ash, slag and sludge. In addition, generating plants and transmission and
distribution facilities have used asbestos, polychlorinated biphenyls (PCBs)
and other hazardous and non-hazardous materials. Substantial costs to store
and dispose of hazardous and non-hazardous materials have been and will
continue to be incurred. Significant additional costs could be incurred to
comply with new laws and regulations if enacted and to clean up disposal
sites under existing legislation.
The Superfund created by the Comprehensive Environmental Response
Compensation and Liability Act addresses cleanup of hazardous substance
disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the cleanup programs. The Company has
been named by the Federal EPA as a "potentially responsible party" (PRP) for
two sites and has received information requests for four other sites.
Although the potential liability associated with each site must be evaluated
individually, several general statements can be made regarding such potential
liability.
Whether the Company disposed of hazardous substances at a particular site
is often unsubstantiated; the quantity of material disposed of at a site was
generally small; and the nature of the material generally disposed of was
non-hazardous. Typically, the Company is one of many parties named PRPs for
a site and, although liability is joint and several, generally at least some
of the other parties are financially sound enterprises. Therefore,
management does not anticipate material cleanup costs for identified disposal
sites. However, if for unknown reasons, significant costs are incurred for
the cleanup of disposal sites, results of operations and financial condition
would be adversely affected unless the costs can by recovered from insurance
proceeds and/or customers.
Regulatory Concerns
Fuel Costs
In recent years, the Company has experienced difficulties recovering all of
the costs of coal produced at its affiliated mines. A stipulation agreement
established, among other things, a predetermined price of $1.64 per million
Btu's for the three-year period ending November 30, 1994. This agreement
applies to four generating plants, three of which are burning affiliated
coal. An inflation adjusted 15-year predetermined price of $1.575 per
million Btu's for coal burned at the Gavin Plant was established beginning
December 1, 1994. After November 2009 the price that can be recovered for
coal from the 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 the Company with an opportunity to accelerate
recovery of its Ohio jurisdictional investment in and liabilities of the
Meigs mining operation including reclamation and other closure costs to the
extent the actual cost of coal burned at the specified plants is less than
the predetermined prices.
In order to maximize acceleration of the recovery of its investment and
future mine closure costs, management restructured its Meigs mining
operation and purchased lower cost replacement coal under long-term
contracts and on the spot market. Restructuring the Meigs operation
reduced per unit production cost and tons produced. Management reviewed the
potential impact of the stipulation on the Company's ability to recover the
cost of the Ohio jurisdictional portion of its Meigs mining operation.
Based on the estimated future cost of coal at Gavin Plant we believe that
the Company should be able to recover, under the terms of the stipulation
agreement, the Ohio jurisdictional portion of the cost of the Meigs mining
operation including mine closure liabilities.
In July 1992 the affiliated Martinka mining operation was sold and the
Company concurrently entered into a 20-year coal contract with an affiliate
of the buyer. The contract will supply up to 2.5 million tons of low-sulfur
coal annually, including coal that will allow the Company to comply with the
CAAA. The Martinka sale did not have a significant impact on results of
operations or financial condition. The contract and sale are subject to PUCO
review in a current fuel clause proceeding.
After the expiration of the three-year predetermined price on November 30,
1994, the Company will pursue recovery of the full Ohio jurisdictional cost
of affiliated coal produced at its Muskingum and Windsor mines. Under the
stipulation agreement the parties agreed to negotiate any dispute concerning
the cost of affiliated fuel burned at the Muskingum River and Cardinal units
after November 30, 1994. As indicated above, compliance with the January 1,
2000 Phase II deadline of the CAAA may cause these mines to close. Manage-
ment intends to seek adequate and timely recovery of any closure costs for
the Muskingum and Windsor mining operations as well as for the cost of the
non-Ohio jurisdictional portion of the Meigs mining operation. In the event
the cost of closing affiliated mines and/or the cost of affiliated coal
cannot be recovered, results of operations and financial condition would be
adversely affected.
Pending Litigation
Meigs Mine
In February 1994 a subsidiary, Southern Ohio Coal Company (SOCCo), returned
its Meigs 31 mine to service after it was inundated with water in July 1993
from an adjoining, sealed and abandoned mine owned by SOCCo. On July 26,
1993 the Ohio Environmental Protection Agency (Ohio EPA) approved a plan to
pump water from the mine and discharge it into Ohio River tributaries under
stringent conditions for biological and water quality monitoring and for
restoring the streams after pumping. Had SOCCo been required to fully treat
all of the water before discharge, it may have been impossible to pump the
water within a reasonable time period to limit damage to the mine and its
equipment and to return the miners to work. To date, pumping has removed
most of the water in the mine.
The Federal EPA and the Federal Office of Surface Mining Reclamation and
Enforcement (OSM) challenged Ohio EPA's jurisdiction and attempted to stop
the state approved pumping. SOCCo sought and received protection in the
federal courts from the attempts of the Federal EPA and OSM to stop the
pumping operation. Since September 16, 1993 all water pumped from the mine
has been treated and discharged in compliance with water discharge permits.
Note 3 of the Notes to Consolidated Financial Statements describes the
details of the litigation.
The outcome of pending litigation as to whether the Federal EPA and OSM had
jurisdiction to stop the pumping of water prior to September 16, 1993 cannot
be predicted. Therefore, it is not possible at this time to determine the
amount of any additional environmental mitigation costs and penalties
that might be imposed if SOCCo is unsuccessful in this litigation.
Management is advised by independent consultants that the damage to the
streams and biological life therein is minor. The mine was returned to
service in February 1994 and an insurance claim was filed for damage to the
mine's equipment. Based on the expected outcome of the litigation, the
amount of the insurance proceeds and status of required environmental
mitigation, management does not expect that the net cost of the Meigs 31 mine
restoration will materially affect results of operations.
Other Litigation
The Company is involved in a number of other legal proceedings and claims.
While management is unable to predict the outcome of such litigation, it is
not expected that the resolution of these other matters will have a material
adverse effect on financial condition.
New Accounting Standards
Two new accounting standards were issued in 1993 that were adopted in 1994.
The implementation of these new standards will not have a significant effect
on results of operations or financial condition.
Effects of Inflation
Inflation affects the cost of replacing utility plant and the cost of
operating and maintaining such plant. The rate-making process limits
recovery of the historical cost of assets resulting in economic losses when
the effects of inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
INDEPENDENT AUDITORS' REPORT
To the Shareowners and Board of
Directors of Ohio Power Company:
We have audited the accompanying consolidated balance sheets of Ohio Power
Company and its subsidiaries as of December 31, 1993 and 1992, and the
related consolidated statements of income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 1993. 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 Ohio Power Company and its
subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1993 in conformity with generally accepted accounting
principles.
As discussed in Notes 1 and 6 in Notes to Consolidated Financial Statements,
effective January 1, 1993, the Company changed its method of accounting for
income taxes to conform with Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes," and its method of accounting for
postretirement benefits other than pensions to conform with Statement of
Financial Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions."
DELOITTE & TOUCHE
Columbus, Ohio
February 22, 1994
Consolidated Statements of Income
Year Ended December 31,
1993 1992 1991
(in thousands)
OPERATING REVENUES $1,708,577 $1,691,597 $1,679,168
OPERATING EXPENSES:
Fuel 640,963 663,120 637,129
Purchased Power 71,260 61,057 76,490
Other Operation 218,793 209,511 200,036
Maintenance 140,756 155,140 149,382
Depreciation and Amortization 128,668 124,461 122,054
Taxes Other Than Federal Income Taxes 168,772 160,295 143,641
Federal Income Taxes 71,178 66,242 84,229
Total Operating Expenses 1,440,390 1,439,826 1,412,961
OPERATING INCOME 268,187 251,771 266,207
NONOPERATING INCOME 18,075 22,391 7,513
INCOME BEFORE INTEREST CHARGES 286,262 274,162 273,720
INTEREST CHARGES 100,492 113,609 107,618
NET INCOME 185,770 160,553 166,102
PREFERRED STOCK DIVIDEND REQUIREMENTS 16,990 17,115 17,112
EARNINGS APPLICABLE TO COMMON STOCK $ 168,780 $ 143,438 $ 148,990
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31,
1993 1992
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,412,973 $2,391,432
Transmission 767,548 758,134
Distribution 766,639 731,559
General (including mining assets) 754,347 773,122
Construction Work in Progress 100,820 79,535
Total Electric Utility Plant 4,802,327 4,733,782
Accumulated Depreciation and Amortization 1,992,082 1,916,011
NET ELECTRIC UTILITY PLANT 2,810,245 2,817,771
OTHER PROPERTY AND INVESTMENTS 138,224 131,211
CURRENT ASSETS:
Cash and Cash Equivalents 20,803 71,056
Accounts Receivable:
Customers 118,133 113,498
Affiliated Companies 27,269 54,466
Miscellaneous 34,733 14,085
Allowance for Uncollectible Accounts (960) (4,353)
Fuel - at average cost 179,554 249,508
Materials and Supplies - at average cost 66,791 69,134
Accrued Utility Revenues 32,234 29,677
Prepayments 43,907 44,281
TOTAL CURRENT ASSETS 522,464 641,352
REGULATORY ASSETS:
Amounts Due From Customers For
Future Federal Income Taxes 433,822 -
Other 211,550 132,020
TOTAL REGULATORY ASSETS 645,372 132,020
TOTAL $4,116,305 $3,722,354
See Notes to Consolidated Financial Statements.
December 31,
1993 1992
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 463,100 464,907
Retained Earnings 474,500 445,955
Total Common Shareowner's Equity 1,258,801 1,232,063
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 126,240 232,978
Subject to Mandatory Redemption 115,000 -
Long-term Debt 1,189,086 1,343,324
TOTAL CAPITALIZATION 2,689,127 2,808,365
OTHER NONCURRENT LIABILITIES 104,172 110,108
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 5,397 22,897
Short-term Debt 40,250 -
Accounts Payable:
General 114,002 66,425
Affiliated Companies 26,087 20,247
Taxes Accrued 168,095 169,406
Interest Accrued 20,862 24,059
Obligations Under Capital Leases 21,916 20,860
Other 107,592 80,358
TOTAL CURRENT LIABILITIES 504,201 404,252
DEFERRED FEDERAL INCOME TAXES 725,283 310,903
DEFERRED INVESTMENT TAX CREDITS 45,795 49,354
REGULATORY LIABILITIES AND DEFERRED CREDITS 47,727 39,372
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $4,116,305 $3,722,354
Consolidated Statements of Cash Flows
Year Ended December 31,
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 185,770 $ 160,553 $ 166,102
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 144,292 143,960 143,325
Deferred Federal Income Taxes (19,607) 3,002 5,783
Deferred Investment Tax Credits (4,222) (4,138) (3,961)
Changes in Certain Current Assets and
Liabilities:
Accounts Receivable (net) (1,479) (67,141) (9,165)
Fuel, Materials and Supplies 72,297 53,036 (30,353)
Accrued Utility Revenues (2,557) 4,176 (2,208)
Accounts Payable 53,417 873 5,043
Other (net) (36,245) (12,565) (25,135)
Net Cash Flows From Operating Activities 391,666 281,756 249,431
INVESTING ACTIVITIES:
Construction Expenditures (161,052) (197,001) (177,096)
Proceeds from Sale of Property and Other 19,124 105,045 2,260
Net Cash Flows Used For Investing Activities (141,928) (91,956) (174,836)
FINANCING ACTIVITIES:
Issuance of Cumulative Preferred Stock 113,610 - -
Issuance of Long-term Debt 517,478 269,231 49,271
Retirement of Cumulative Preferred Stock (109,187) - (157)
Retirement of Long-term Debt (704,959) (145,461) (7,910)
Change in Short-term Debt (net) 40,250 (133,533) 44,968
Dividends Paid on Common Stock (140,042) (134,172) (133,054)
Dividends Paid on Cumulative Preferred Stock (17,141) (17,115) (17,114)
Net Cash Flows Used For Financing Activities (299,991) (161,050) (63,996)
Net Increase (Decrease) in Cash and Cash Equivalents (50,253) 28,750 10,599
Cash and Cash Equivalents January 1 71,056 42,306 31,707
Cash and Cash Equivalents December 31 $ 20,803 $ 71,056 $ 42,306
See Notes to Consolidated Financial Statements.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1993 1992 1991
(in thousands)
Retained Earnings January 1 $445,955 $436,689 $420,755
Net Income 185,770 160,553 166,102
631,725 597,242 586,857
Deductions:
Cash Dividends Declared:
Common Stock 140,042 134,172 133,054
Cumulative Preferred Stock:
4.08% Series 204 204 204
4-1/2% Series 911 911 911
4.20% Series 252 252 252
4.40% Series 440 440 440
5.90% Series 199 - -
6.02% Series 321 - -
6.35% Series 1,196 - -
7.60% Series 2,660 2,660 2,660
7-6/10% Series 2,660 2,660 2,660
7.72% Series 691 772 772
7.76% Series 3,337 3,492 3,492
8.04% Series 1,206 1,206 1,206
8.48% Series 2,275 2,544 2,544
$2.27 Series 789 1,974 1,973
Total Dividends 157,183 151,287 150,168
Other 42 - -
Total Deductions 157,225 151,287 150,168
Retained Earnings December 31 $474,500 $445,955 $436,689
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Ohio Power Company (the Company or OPCo) is a wholly-owned subsidiary of
American Electric Power Company, Inc. (AEP Co., Inc.), a public utility
holding company. The Company is engaged in the generation, purchase,
transmission and distribution of electric power in northwestern, east
central, eastern and southern sections of Ohio. As a member of the American
Electric Power (AEP) System Power Pool (Power Pool) and a signatory company
to the AEP Transmission Equalization Agreement, its facilities are operated
in conjunction with the facilities of certain other AEP Co., Inc. owned
utilities as an integrated system.
The Company has three coal-mining subsidiaries: Central Ohio Coal Company
(COCCo), Southern Ohio Coal Company (SOCCo) and Windsor Coal Company (WCCo)
which conduct mining operations at the Muskingum mine, Meigs mine and Windsor
mine, respectively. Coal produced by the coal-mining subsidiaries is sold to
the Company at cost plus a Securities and Exchange Commission (SEC) approved
return on investment.
Regulation
As a member of the AEP System, OPCo is subject to regulation by the SEC
under the Public Utility Holding Company Act of 1935 (1935 Act). Retail
rates are regulated by the Public Utilities Commission of Ohio (PUCO). The
Federal Energy Regulatory Commission (FERC) regulates wholesale rates.
Principles of Consolidation
The consolidated financial statements include OPCo and its wholly-owned
subsidiaries. Significant intercompany items were eliminated in consol-
idation.
Basis of Accounting
As a rate-regulated entity, OPCo's 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 (SFAS 71),
regulatory assets and liabilities are recorded to defer expenses or revenues
reflecting such rate-making differences.
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 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 9.50% in 1993, 7.25% in 1992 and 6% in 1991,
and the amounts of AFUDC accrued were $5 million in 1993, $4 million in 1992
and $2 million in 1991.
Depreciation, Depletion and Amortization
Depreciation is provided on a straight-line basis over the estimated
useful lives of utility plant other than coal-mining property and is
calculated largely through the use of composite rates by functional class
(i.e., production, transmission, distribution, etc.). Amounts to be used for
plant demolition are presently recovered through depreciation charges
included in rates. Depreciation, depletion and amortization of coal-mining
assets are provided over their estimated useful lives and are calculated
using the straight-line method for mining structures and equipment and the
units-of-production method for coal rights and mine development costs and 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.
Operating Revenues
Revenues include an accrual for electricity consumed but unbilled at
month-end as well as billed revenues.
Fuel Costs
Changes in retail jurisdictional fuel cost are deferred until reflected in
revenues in later months through a PUCO fuel cost recovery mechanism.
Wholesale jurisdictional fuel cost changes are expensed and billed as
incurred.
Income Taxes
Effective January 1, 1993, the Company adopted the liability method of
accounting for income taxes as prescribed by SFAS 109, Accounting for Income
Taxes. Under this standard deferred federal income taxes are provided for
all temporary differences between the book cost and tax basis of assets and
liabilities which will result in a future tax consequence. In prior years
deferred federal income taxes were provided for differences between book and
taxable income except where flow-through accounting for certain differences
was reflected in rates. Flow-through accounting is a method whereby federal
income tax expense for a particular item is the same for accounting and rate-
making as in the federal income tax return. As a result of the adoption of
SFAS 109 significant additional deferred tax liabilities were recorded for
items afforded flow-through treatment in rates. In accordance with SFAS 71
significant corresponding regulatory assets were also recorded to reflect the
future recovery of additional taxes due when the temporary differences
reverse. As a result of this change in accounting effective January 1, 1993,
deferred federal income tax liabilities increased by $403.4 million and
regulatory assets by $407 million, and net income was increased by $3.6
million.
Investment tax credits utilized in prior years' federal income tax returns
were deferred and are being amortized over the life of the related plant
investment in accordance with rate-making treatment.
Debt and Preferred Stock
Gains and losses on reacquired debt are deferred and amortized over the
term of the reacquired debt. If the debt is refinanced the reacquisition
costs are deferred and amortized over the term of the replacement debt.
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 and
amortized 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
Other property and investments are generally stated at cost.
Reclassifications
Certain prior-period amounts were reclassified to conform with current-
period presentation.
2. RATE MATTERS:
Recovery of Fuel Costs
On June 24, 1993, the FERC issued an order to the Company authorizing
recovery of 1988 FERC ordered refunds to wholesale customers and foregone
fuel cost recoveries, including interest, related to the cost of coal from
the affiliated Martinka mining operations. With the favorable conclusion of
this litigation in December 1992, the favorable impact on results of
operations was recorded in 1992.
OPCo sold its affiliated Martinka mining operation in July 1992 and
concurrently entered into a 20-year coal-supply contract with an affiliate of
the buyer. Under the contract OPCo will purchase up to 2.5 million tons of
low-sulfur coal annually, including coal that will allow compliance with the
Clean Air Act Amendments of 1990 (CAAA). The Martinka sale did not have a
significant impact on results of operations or financial condition. The
contract and sale are subject to PUCO review in a current fuel clause
proceeding.
On September 1, 1993, the municipal wholesale customers appealed to the
U.S. Court of Appeals FERC orders that dismissed an April 1991 complaint.
This complaint involved the same issues that were favorably resolved in
litigation concerning FERC jurisdictional fuel recoveries from the Martinka
mine. Another complaint of the municipal wholesale customers filed with the
FERC in November 1992 requesting an investigation of the Martinka sale was
dismissed in June 1993. The municipal wholesale customers also filed a com-
plaint in November 1992 with the SEC requesting an investigation of the
Martinka sale and an investigation into the pricing of affiliated coal
purchases back to 1986. Since the SEC has not responded to the complaint,
the Company cannot predict the ultimate outcome of this matter.
Coal costs for four of the Company's generating plants, three of which
burn affiliated coal from the Muskingum, Windsor and Meigs mining operations,
are subject to a predetermined price of $1.64 per million Btu's for the
three-year period ending November 30, 1994. Beginning December 1, 1994 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 adjustments. After November
2009 the price that the Company can recover for coal from the 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 an
opportunity to accelerate recovery of the investment in and the liabilities
of the Meigs mining operations attributable to the Ohio jurisdiction to the
extent the actual cost of coal burned at the four plants is below the prede-
termined prices.
Based on the estimated future cost of coal supplied to the Gavin Plant,
both Meigs and unaffiliated coal, management believes that the Ohio jurisdic-
tional portion of the cost of the Meigs mining operations including mine
closure liabilities will be recovered under the terms of the stipulation
agreement.
Recovery of the Ohio jurisdictional cost of coal produced at the
affiliated Muskingum and Windsor mines will be pursued after the expiration
of the three-year predetermined price in November 1994. In the stipulation
agreement the parties agreed to negotiate any dispute concerning the cost of
affiliated coal burned at the Company's Muskingum River and Cardinal units
after November 30, 1994. The Muskingum mine supplies Muskingum Plant and the
Windsor mine supplies the Cardinal Plant. As discussed in Note 3 under
"Clean Air" the Muskingum and Windsor mines may have to close as part of
compliance with the CAAA. Management believes that costs of compliance with
the CAAA should be recoverable from ratepayers and intends to seek adequate
and timely recovery of any closure costs for the Muskingum and Windsor mining
operations as well as for the non-Ohio jurisdictional portion of the Meigs
mining operation. Unless the cost of affiliated mine closures and/or the
cost of coal can be recovered from customers, results of operations and
financial condition would be adversely affected.
PFBC Demonstration Plant
The Company constructed a pressurized fluidized bed combustion (PFBC)
demonstration plant at a December 31, 1993 cost of $182 million to dem-
onstrate and further test this new technology for removing sulfur from coal.
A one year extension on the three-year test operation of the PFBC plant that
is scheduled to end March 1994 has been requested. The three-year test is
estimated to have cost $25 million, and the extension, if granted, will
require additional expenditures. The Company qualified for funding from the
U.S. Department of Energy (DOE) and the State of Ohio and received $59.5
million and $10 million, respectively. The Company has recovered from
ratepayers the PFBC plant costs which are not being funded by the DOE and the
State through its retail electric fuel component (EFC) at a rate of 1 mill
per kwh through November 1993 and a rate of 0.3228 mill per kwh thereafter.
Continued recovery through the EFC is subject to semi-annual review and
approval by the PUCO.
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Construction program expenditures for 1994-1996 are estimated to be $484
million and include capital costs for compliance with the CAAA except for the
cost of the flue gas desulfurization system (scrubbers) for the two-unit
2,600 megawatt Gavin Plant. In 1992, the Company entered into an agreement
for construction and lease of the Gavin Plant scrubbers with JMG Funding
Partnership, an unaffiliated company. The lease will be accounted for as an
operating lease.
In addition to fuel acquired from coal-mining subsidiaries and spot-
markets, the Company has long-term fuel supply contracts with unaffiliated
companies. The contracts generally contain clauses that provide for periodic
price adjustments. The Company's retail jurisdictional fuel clause mechanism
provides, with the regulator's review and approval, for deferred recovery of
changes in the cost of fuel except for contracts for coal received at four of
the Company's seven coal-fired generating plants through November 1994.
After November 1994 the exception will only apply to coal received at the
Gavin Plant. (See Note 2 for further details on the application of a
predetermined price). The contracts are for various terms, the longest of
which extends to 2012, and contain clauses that would release the Company
from its obligation under certain force majeure conditions.
Clean Air
The CAAA requires significant reductions in sulfur dioxide and nitrogen
oxides emitted from various AEP System generating plants. The law
established a deadline of 1995 for the first phase of reductions in sulfur
dioxide emissions (Phase I) and the year 2000 for the second phase (Phase II)
as well as a permanent nationwide cap on sulfur dioxide emissions after 1999.
In April 1992, the Company filed a systemwide Phase I CAAA compliance plan
with the PUCO. The selection of compliance alternatives for the AEP System's
generating plants was dependent upon the compliance method selected for the
Company's two-unit 2,600 megawatt Gavin Plant, which emits about 25% of the
System's total sulfur dioxide emissions. The compliance plan filing was made
under a 1991 Ohio law that provides an opportunity for utilities to obtain
advance PUCO approval of a least-cost approach compliance plan. Once ap-
proved, such plans are deemed prudent by state law for subsequent PUCO rate
proceedings. In November 1992, the PUCO issued an order approving the
Company's compliance plan and a related stipulation agreement with the PUCO
staff and the Ohio Consumers' Counsel.
The stipulation agreement with the PUCO staff and the Ohio Consumers'
Counsel limits the recoverable cost of the Gavin scrubbers to $815 million.
Management currently expects that the cost of the scrubbers will be at least
10% less than this cap.
The PUCO approved plan sets forth compliance measures for the System's
affected generating units, including: installation of leased scrubbers at the
Gavin Plant; burning Ohio high-sulfur coal at Gavin supplied by the
affiliated Meigs mine which will operate at reduced capacity and by replace-
ment coal from new long-term contracts with unaffiliated sources and spot
market purchases; and switching from high-sulfur coal to an alternate fuel at
other System units.
The planned fuel switching may result in the shutdown of the Company's
Muskingum and Windsor coal-mining operations. Shutdown costs for Muskingum
and Windsor include investments in the mines, leased asset buy-outs,
reclamation and employee benefits and are estimated to be approximately $250
million at December 31, 1993. Lack of recovery of the cost of CAAA
compliance, including the lease cost of the Gavin scrubbers and the
investment in and cost of closing affected affiliated mining operations,
would adversely affect results of operations and financial condition.
Management believes that costs of compliance with the CAAA should be
recoverable from rate-payers and intends to seek recovery in the near future.
Other Environmental Matters
The Company and its subsidiaries are subject to regulation by federal,
state and local authorities with respect to air and water quality and other
environmental matters.
The generation of electricity produces non-hazardous and hazardous by-
products. Asbestos, polychlorinated biphenyls (PCBs) and other hazardous
materials have been used in the generating plants and
transmission/distribution facilities. Substantial costs to store and dispose
of hazardous and non-hazardous materials have been incurred and will be
incurred. Significant additional costs could be incurred in the future to
meet the requirements of new laws and regulations, if enacted, and to clean
up existing disposal sites under existing legislation.
The Company has been named a "potentially responsible party" (PRP) by the
United States Environmental Protection Agency (Federal EPA) for two disposal
sites and has received information requests for four other sites. Although
the potential liability associated with each site must be evaluated indi-
vidually, several general statements can be made regarding such potential
liability.
Whether the Company disposed of hazardous substances at a particular site
is often unsubstantiated; the quantity of material disposed of at a site was
generally small; and the nature of the material generally disposed of was
non-hazardous. Typically, the Company is one of many parties named PRPs for
a site and, although liability is joint and several, generally at least some
of the other parties are financially sound enterprises. Therefore,
management does not anticipate material cleanup costs for identified disposal
sites. However, if for unknown reasons, significant costs are incurred for
cleanup, results of operations and financial condition would be adversely
affected unless the costs can be recovered from insurance proceeds and/or
customers.
Meigs Mine Litigation
On July 11, 1993, Meigs 31 mine, one of two underground mines owned by
SOCCo was inundated with water from an adjoining, sealed and abandoned mine
also owned by SOCCo. On July 26, 1993, the Ohio Environmental Protection
Agency (Ohio EPA) approved a plan to pump water from the mine.
The U.S. District Court for the Southern District of Ohio granted a motion
by SOCCo for a preliminary injunction against the Federal Office of Surface
Mining Reclamation and Enforcement (OSM) and Federal EPA preventing them from
exercising jurisdiction to issue orders to cease the pumping. In an appeal
by Federal EPA and OSM the U.S. Court of Appeals for the Sixth Circuit denied
OSM's motion for a stay of the District Court's preliminary injunction but
granted Federal EPA's motion for a stay in part which allowed Federal EPA to
investigate and make findings with respect to alleged violations of the Clean
Water Act and thereafter to exercise its enforcement authority under the
Clean Water Act if a violation was identified. Federal EPA issued an
administrative order requiring a partial cessation of pumping which was
extended until September 8, 1993. On September 8, 1993, the District Court
granted SOCCo's motion requesting that enforcement of the Federal EPA order
be stayed. On September 23, 1993, the Court of Appeals ruled that Federal
EPA had the right to issue the order, thereby overturning the District
Court's decision. Since September 16, 1993, SOCCo has processed all water
removed from the mine through its expanded treatment system and is in
compliance with the effluent limitations in its water discharge permits.
On January 3, 1994 the District Court held that the complaint filed by
SOCCo should not be dismissed and concluded that sufficient legal and factual
grounds existed for the court to consider SOCCo's claim that Federal EPA
could not override Ohio EPA's authorization for SOCCo to bypass its water
treatment system on an emergency basis during pumping activities. In a
separate opinion, the District Court denied Federal EPA's request that the
District Court defer consideration of SOCCo's motion involving a request for
a Declaration of Rights with respect to the mine water releases into area
streams.
The West Virginia Division of Environmental Protection has proposed fining
SOCCo $1.8 million for alleged violations resulting from the release of mine
water into the Ohio River.
Pumping has removed most of the water that inundated the mine. Meigs 31
mine returned to service in February 1994. The resolution of the
aforementioned litigation and environmental mitigation costs is not expected
to have a material adverse impact on results of operations or financial
condition.
Other Litigation
The Company is involved in a number of other legal proceedings and claims.
While management is unable to predict the outcome of litigation, it is not
expected that the resolution of these other matters will have a material
adverse effect on financial condition.
4. COMMON SHAREOWNER'S EQUITY:
Mortgage indentures, debentures, charter provisions and orders of
regulatory authorities place various restrictions on the use of retained
earnings for the payment of cash dividends on common stock. At December 31,
1993, $156.5 million of retained earnings were restricted. Regulatory
approval is required to pay dividends out of paid-in capital.
In 1993, charges to paid-in capital of $1.8 million represented the
issuance expense of new cumulative preferred stock and the write-off of
premiums on retired cumulative preferred stock. There were no other material
transactions affecting common stock and paid-in capital in 1993, 1992 or
1991.
5. RELATED PARTY TRANSACTIONS:
Benefits and costs of the System's generating plants are shared by members
of the Power Pool. Under the terms of the System Interconnection Agreement,
capacity charges and credits are designed to allocate the cost of the
System's capacity among the Power Pool members based on their relative peak
demands and generating reserves. Power Pool members are compensated for the
out-of-pocket costs of energy delivered to the Power Pool and charged for
energy received from the Power Pool. The Company is a net supplier to the
pool and, therefore, receives net capacity credits from the Power Pool.
Operating revenues include $255.7 million in 1993, $291.9 million in 1992
and $255.6 million in 1991 for supplying energy and capacity to the Power
Pool. Purchased power expense includes charges of $38.9 million in 1993,
$29.1 million in 1992 and $34.8 million in 1991 for energy received from the
Power Pool.
Power Pool members share in wholesale sales to unaffiliated utilities made
by the Power Pool. The Company's share was included in operating revenues in
the amount of $97.3 million in 1993, $79.8 million in 1992 and $109.5 million
in 1991.
In addition, the Power Pool purchases power from unaffiliated companies
for immediate resale to other unaffiliated utilities. The Company's share of
these purchases was included in purchased power expense and totaled $19.8
million in 1993, $20.4 million in 1992 and $29.8 million in 1991. Revenues
from these transactions are included in the above Power Pool wholesale sales.
Purchased power expense includes energy bought from Ohio Valley Electric
Corporation, an affiliated company that is not a member of the Power Pool, in
the amounts of $7.1 million in 1993, $5.9 million in 1992 and $4.7 million in
1991.
Operating revenues include energy sold directly to Wheeling Power Company
in the amounts of $57.6 million in 1993, $62.1 million in 1992, and $62.8
million in 1991. Wheeling Power Company is an affiliated distribution
utility that is not a member of the Power Pool.
AEP System companies participate in a transmission equalization agreement.
This agreement combines certain AEP System companies' investments in
transmission facilities and shares the costs of ownership in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, charges of $16.8 million, $14.5 million and $13.5 million were
recorded in other operation expense for transmission services in 1993, 1992
and 1991, respectively.
The Company purchased coal from its mining subsidiaries paying its
subsidiaries $331.7 million in 1993, $398.1 million in 1992 and $493 million
in 1991 for affiliated coal. Coal-transportation costs paid to an affiliated
company other than its coal-mining subsidiaries aggregate approximately $8.6
million, $4 million and $4.4 million in 1993, 1992 and 1991, respectively.
Fuel expense includes charges for the transportation of coal from an
affiliate and for the mining of coal from its subsidiaries. The prices
charged by the subsidiaries for coal and by the affiliate for coal
transportation services are computed generally in accordance with orders
issued by the SEC.
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are determined by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the use
of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
6. BENEFIT PLANS:
AEP System Pension Plan
The Company and its subsidiaries participate in the AEP pension plan, 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. Effective January 1, 1992 employees may retire without
reduction of benefits at age 62 and with reduced benefits as early as age 55.
Pension costs are allocated by first charging each System company with its
service cost and then allocating the remaining pension cost in proportion to
its share of the projected benefit obligation. 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 contribution required by law.
The Company's share of net pension cost of the AEP System Pension Plan for
the years ended December 31, 1993, 1992 and 1991 was $5.9 million, $8 million
and $3.2 million, respectively.
AEP System Savings Plan
An employee savings plan is offered to non-UMWA employees which allows
participants to contribute up to 16% of their salaries into three investment
alternatives, including AEP Co., Inc. common stock. The Company contributes
an amount equal to one-half of the first 6% of the employees' contribution.
The Company's contribution is invested in AEP Co., Inc. common stock and
totaled $4.3 million in 1993, 1992 and 1991.
UMWA Pension Plans
The Company's coal-mining subsidiaries contribute to UMWA pension funds to
provide pension benefits for UMWA employees meeting eligibility requirements.
Benefits are based on age at retirement and years of service. As of June 30,
1993, the UMWA actuary estimates that the coal-mining subsidiaries' share of
the UMWA pension plans unfunded vested liabilities was approximately $44
million. In the event the coal-mining subsidiaries cease or significantly
reduce mining operations or contributions to the pension plans, a withdrawal
obligation may be triggered for all or a portion of their share of the
unfunded vested liability. Employer contributions are based on the number of
hours worked, are expensed when paid and totaled $1.6 million in 1993, $2.1
million in 1992 and $3 million in 1991.
Postretirement Benefits Other Than Pensions
The AEP System provides certain other benefits for retired employees.
Substantially all non-UMWA employees are eligible for health care and life
insurance benefits if they have at least 10 service years and, effective
January 1, 1992, are age 55 at retirement. Prior to 1993, net costs of these
benefits were recognized as an expense when paid and totaled $3.1 million and
$3.2 million in 1992 and 1991, respectively.
Medical benefits for the Company's UMWA retirees who retired after January
1, 1976 and the Company's active UMWA employees are the liability of the
coal-mining subsidiaries. UMWA employees are eligible for medical and life
insurance benefits if they have at least 10 service years and are at least
age 55 at retirement. Former UMWA employees become eligible at age 55 if
they have 20 service years. The cost of health care benefits for this group
was also expensed when paid in 1992 and 1991 and totaled $16.5 million in
both years.
SFAS 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions, was adopted in January 1993 for the Company's aggregate
postretirement benefits other than pensions (OPEB) liability. SFAS 106
requires the accrual of the present value liability for OPEB costs during the
employee's service years. Prior service costs are being recognized as a
transition obligation over 20 years in accordance with SFAS 106. OPEB costs
are based on actuarially-determined stand alone costs for each System
company. The funding policy is to contribute incremental amounts recovered
through rates and cash generated by the corporate owned life insurance (COLI)
program. The annual accrued costs for 1993 required by SFAS 106 for
employees and retirees, which includes the recognition of one-twentieth of
the prior service transition obligation, was $34.2 million.
The Company received authority from the FERC and PUCO 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 in the next base rate filings. At December 31, 1993, $9 million of
such OPEB costs were deferred.
To reduce the impact of adopting SFAS 106, management took several
measures. First, a Voluntary Employees Beneficiary Association (VEBA) trust
fund for OPEB benefits for all non-UMWA employees was established. A $6.3
million advance contribution was made to the trust fund in 1990, the maximum
amount deductible for federal income tax purposes. In 1993, a $2.3 million
contribution was made to the VEBA trust fund from amounts recovered from
ratepayers. In addition, to help fund and reduce the future costs of OPEB
benefits, a 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, as other property and
investments. The policies generated cash of $2.5 million in 1993, $1.5
million in 1992 and $370,000 in 1991 inclusive of related tax benefits which
was contributed to the VEBA trust fund. In 1997 the premium will be fully
paid and the cash generated by the policies should increase significantly.
UMWA health plans pay the 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 Energy Policy Act of 1992 secured lifetime
medical benefits for these retirees; reimposed funding obligations upon
companies who previously withdrew from the UMWA plans; eliminated the
withdrawal liability; eliminated the per-hour worked contribution feature for
the 1950 and 1974 UMWA Benefit Plans; assigned beneficiaries to their former
employers; and assigned to signatories on a pro rata basis those
beneficiaries who could not otherwise be assigned. In February 1993, the
1950 and 1974 UMWA Benefit Plans were merged into the UMWA Combined Benefit
Fund and a 1992 Benefit Plan was added. The Combined Fund is financed by
payments from current and former UMWA wage agreement signatories, the 1950
UMWA Pension Plan surplus and the Abandoned Mine Land Reclamation Fund
Surplus. Costs of the 1992 Benefit Plan are paid by signatories to 1988 and
prior years' UMWA contracts. Required annual payments to the UMWA health
funds made by the coal-mining subsidiaries were recognized as expense when
paid and totaled $1.2 million in 1993, $9.8 million in 1992 and $11.6 million
in 1991.
The recently negotiated 1993 National Bituminous Coal Wage Agreement
provides for establishment of the UMWA 1993 Benefit Plan for future orphaned
retirees not covered by the Energy Act. The 1993 Benefit Plan will be funded
by signatory operators with a per-hour-worked contribution during the
duration of the Agreement. Health benefits under this Plan are provided only
for the duration of the Agreement. In 1993 contributions under the Agreement
were not significant.
The Energy Act also permits recovery, within established limits, of excess
funding in the Black Lung Trust funds equal to the expense of certain
benefits other than pensions for those covered by the UMWA Combined Benefit
Fund. In 1993, $8 million of Black Lung surplus was applied in accordance
with the Energy Act to reimburse the coal companies for benefits paid in 1992
and the first nine months of 1993. The Company's coal subsidiaries' share of
Black Lung Trust excess funds at December 31, 1993 and 1992 was $17 million
and $25 million, respectively, and may be applied to reimburse the coal-
subsidiaries for benefits provided in the future.
7. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1993 1992 1991
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $ 83,471 $57,487 $77,686
Deferred (10,477) 10,487 8,101
Deferred Investment Tax Credits (1,816) (1,732) (1,558)
Total 71,178 66,242 84,229
Charged (Credited) to Nonoperating Income (net):
Current 4,602 19,432 (1,028)
Deferred (9,130) (7,485) (2,318)
Deferred Investment Tax Credits (2,406) (2,406) (2,403)
Total (6,934) 9,541 (5,749)
Total Federal Income Taxes as Reported $ 64,244 $75,783 $78,480
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,
1993 1992 1991
(in thousands)
Net Income $185,770 $160,553 $166,102
Federal Income Taxes 64,244 75,783 78,480
Pre-tax Book Income $250,014 $236,336 $244,582
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35% in 1993 and 34% in 1992 and 1991) $ 87,505 $80,354 $83,158
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 9,644 10,179 8,349
Property Tax Accruals 69 (1,548) 6,049
Removal Costs (9,030) (5,651) (4,814)
Corporate Owned Life Insurance (9,318) (9,010) (5,238)
Investment Tax Credits (net) (4,221) (3,986) (4,311)
Sale of Martinka Mining Property - 7,825 -
Other (10,405) (2,380) (4,713)
Total Federal Income Taxes as Reported $ 64,244 $75,783 $78,480
Effective Federal Income Tax Rate 25.7% 32.1% 32.1%
The following are the principal components of federal income taxes as reported:
Year Ended December 31,
1993 1992 1991
(in thousands)
Current:
Federal Income Taxes $ 88,072 $76,767 $77,008
Investment Tax Credits 1 152 (350)
Total Current Federal Income Taxes 88,073 76,919 76,658
Deferred:
Depreciation 4,075 2,638 5,150
Tidd Pressurized Fluidized Bed Combustion
Research and Development (946) 1,257 (4,203)
Business and Occupation Tax Provision - - 5,001
Sale of Martinka Mining Property - (4,132) -
Martinka Fuel Cost Recoveries (9,580) 5,037 -
Postretirement Benefits Other Than Pensions (4,899) - -
Other (8,257) (1,798) (165)
Total Deferred Federal Income Taxes (19,607) 3,002 5,783
Total Deferred Investment Tax Credits (4,222) (4,138) (3,961)
Total Federal Income Taxes as Reported $ 64,244 $75,783 $78,480
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliates in the AEP System. The
allocation of the AEP System's current consolidated federal income tax to the
System companies is in accordance with SEC rules under the 1935 Act. These
rules permit the allocation of the benefit of current tax losses and
investment tax credits utilized to the System companies giving rise to them
in determining their current tax expense. The tax loss of the System parent
company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.
With the exception of the loss of the parent company, the method of
allocation approximates a separate return result for each company in the
consolidated group.
The AEP System settled with the Internal Revenue Service (IRS) all issues
from the audits of the consolidated federal income tax returns for the years
prior to 1988. Returns for 1988 through 1990 are 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.
The net deferred tax liability of $725.3 million at December 31, 1993 is
composed of deferred tax assets of $134.6 million and deferred tax
liabilities of $859.9 million. The significant temporary differences giving
rise to the net deferred tax liability are:
Deferred Tax Asset
(Liability)
(in thousands)
Property Related
Temporary Differences $(589,901)
Amounts Due From Customers
For Future Federal Income Taxes (151,838)
All Other (net) 16,456
Total Net Deferred Tax Liability $(725,283)
8. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1993 1992 1991
(in thousands)
Taxes Other Than Federal
Income Taxes include:
Real and Personal
Property $ 70,639 $ 69,623 $ 67,896
Gross Receipts 50,693 50,297 49,868
Business and
Occupation 32,447 26,901 11,498
Payroll 9,600 9,765 9,563
State Income 2,626 1,082 1,898
Other 2,767 2,627 2,918
Total $168,772 $160,295 $143,641
Fuel includes charges
relating to affiliated
coal-mining operations
as follows:
Maintenance $56,120 $ 72,194 $ 90,822
Depreciation,
Depletion and
Amortization 14,824 18,910 20,924
Taxes Other Than
Federal Income
Taxes 20,758 27,298 35,997
Total $91,702 $118,402 $147,743
Cash was paid for:
Interest (net of
capitalized
amounts) $101,659 $112,365 $104,460
Income Taxes $95,684 $83,164 $75,373
Noncash Acquisitions
Under Capital Leases
were $33,097 $23,036 $51,260
In connection with the 1992 sale of Martinka operations the Company is
receiving cash payments from the buyer of $77 million over a 13-1/2 year
period which had a net present value of $44.6 million at the time of the
sale.
9. LEASES:
Leases of property, plant and equipment are for periods up to 30 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 generally charged to operating expense in accordance
with rate-making treatment. The components of rentals are as follows:
Year Ended December 31,
1993 1992 1991
(in thousands)
Operating Leases $26,432 $43,209 $40,685
Amortization of
Capital Leases 20,352 20,034 24,790
Interest on
Capital Leases 6,539 8,371 9,217
Total Rental Payments $53,323 $71,614 $74,692
Properties under capital leases and related obligations recorded on
the Consolidated Balance Sheets are as follows:
December 31,
1993 1992
(in thousands)
Electric Utility Plant:
Production $ 5,248 $ 30,204
General (including mining assets) 160,929 173,246
Total Electric Utility Plant 166,177 203,450
Accumulated Amortization 84,400 107,282
Net Electric Utility Plant 81,777 96,168
Other Property 15,552 -
Net Property under
Capital Leases $ 97,329 $ 96,168
Obligations under Capital Leases $97,329 $96,168
Less Portion Due Within One Year 21,916 20,860
Noncurrent Liability $75,413 $75,308
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,
1993:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1994 $ 28,180 $ 26,015
1995 23,409 24,386
1996 18,162 22,406
1997 13,807 19,970
1998 9,768 18,174
Later Years 21,645 154,017
Total Future Minimum Lease Rentals 114,971 $264,968
Less Estimated Interest Element 17,642
Estimated Present Value of
Future Minimum Lease Rentals $ 97,329
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1993, authorized shares of cumulative preferred stock were
as follows:
Par Value Shares Authorized
$100 3,762,403
25 4,000,000
Unissued shares of the cumulative preferred stock may or may not possess
mandatory redemption characteristics upon issuance. The cumulative preferred
stock is callable at the price indicated plus accrued dividends. The
involuntary liquidation preference is par value.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1993 Value Year Ended December 31, December 31, 1993 1993 1992
1993 1992 1991 (in thousands)
4.08% $103 $100 - - - 50,000 $ 5,000 $ 5,000
4-1/2% 110 100 - - - 202,403 20,240 20,240
4.20% 103.20 100 - - - 60,000 6,000 6,000
4.40% 104 100 - - - 100,000 10,000 10,000
7.60% 102.26 100 - - - 350,000 35,000 35,000
7-6/10% 102.11 100 - - - 350,000 35,000 35,000
7.72% - 100 100,000 - - - - 10,000
7.76% - 100 450,000 - - - - 45,000
8.04% 102.58 100 - - - 150,000 15,000 15,000
8.48% - 100 300,000 - - - - 30,000
$2.27 - 25 869,500 - 6,200 - - 21,738
$126,240 $232,978
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Outstanding December 31,
Series(a) Value December 31, 1993 1993 1992
(in thousands)
5.90% (b) $100 450,000 $ 45,000 -
6.02% (c) 100 400,000 40,000 -
6.35% (d) 100 300,000 30,000 -
$115,000 $ -
(a) Not callable until after 2002. There are no aggregate sinking fund provisions through 1998.
(b) Shares issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90%
cumulative preferred stock will require the redemption of 22,500 shares each year and the redemption of the remaining
shares outstanding on January 1, 2009, in each case at $100 per share.
(c) Shares issued October 1993. Commencing in 2003 and continuing through the year 2007, a sinking fund for the 6.02%
cumulative preferred stock will require the redemption of 20,000 shares each year and the redemption of the remaining
shares outstanding on December 1, 2008, in each case at $100 per share.
(d) Shares issued April 1993. Commencing in 2003 and continuing through the year 2007, a sinking fund for the 6.35%
cumulative preferred stock will require the redemption of 15,000 shares each year and the redemption of the remaining
shares outstanding on June 1, 2008, in each case at $100 per share.
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1993 1992
(in thousands)
First Mortgage Bonds $ 842,981 $ 998,771
Installment Purchase
Contracts 232,103 232,642
Notes Payable to Banks 95,000 110,000
Sinking Fund Debentures 17,884 17,895
Other 6,515 6,913
1,194,483 1,366,221
Less Portion Due Within
One Year 5,397 22,897
Total $1,189,086 $1,343,324
First mortgage bonds outstanding were as follows:
December 31,
1993 1992
(in thousands)
% Rate Due
9 1994 - December 1 $ - $ 80,000
5 1996 - January 1 38,759 38,759
6-1/2 1997 - August 1 46,620 46,620
6-3/4 1998 - March 1 55,661 55,661
9-7/8 1998 - June 1 - 100,000
7-3/4 1999 - March 1 - 67,786
8.10 2002 - February 15 50,000 50,000
8.25 2002 - March 15 50,000 50,000
7-5/8 2002 - April 1 16,910 16,910
9-1/4 2002 - April 1 - 72,500
7-3/4 2002 - October 1 24,000 24,000
6.75 2003 - April 1 40,000 -
6.875 2003 - June 1 40,000 -
8-3/8 2003 - August 1 - 40,000
6.55 2003 - October 1 40,000 -
6.00 2003 - November 1 25,000 -
6.15 2003 - December 1 50,000 -
9-1/4 2006 - November 1 - 80,000
9 2007 - April 1 - 40,000
9-1/4 2008 - March 1 - 38,000
9-7/8 2020 - August 1 50,000 50,000
9.625 2021 - June 1 50,000 50,000
8.80 2022 - February 10 50,000 50,000
8.75 2022 - June 1 50,000 50,000
7.75 2023 - April 1 40,000 -
7.85 2023 - June 1 40,000 -
7.375 2023 - October 1 40,000 -
7.10 2023 - November 1 25,000 -
7.30 2024 - April 1 25,000 -
Unamortized Discount (net) (3,969) (1,465)
842,981 998,771
Less Portion Due Within One year - 7,500
Total $842,981 $991,271
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee or, in lieu thereof, certification of unfunded
property additions.
Sinking fund debentures outstanding were as follows:
December 31,
1993 1992
(in thousands)
5-1/8% Series
due 1996 - January 1 $ 8,691 $ 8,691
6-5/8% Series
due 1997 - August 1 4,253 4,253
7-7/8% Series
due 1999 - March 1 4,905 4,905
Unamortized Premium 35 46
Total $17,884 $17,895
Prior to December 31, 1993 sufficient principal amounts of debentures had
been reacquired to satisfy all future sinking fund requirements. The Company
may make additional sinking fund payments of up to $1.5 million annually.
The notes payable to banks have due dates ranging from January 1994 to
January 1998 with interest payable quarterly at rates ranging from 5.79% to
8.01%. In January 1994, one of the subsidiaries entered into three term loan
agreements due January 2001 totaling $30 million with 6.20% fixed interest
rates and one $15 million variable interest rate term loan agreement due in
January 1999 with a 3.725% initial rate through July 1994. The proceeds were
used in January 1994 to pay at maturity two fixed interest rate term loans,
$20 million at 8.00% and $25 million at 8.01%. As a result, the $45 million
of term loans are reported as long-term in the financial statements.
Installment purchase contracts have been entered into in connection with
the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
1993 1992
(in thousands)
Ohio Air Quality Development
7.4% Series B
due 2009 - August 1 $ 50,000 $ 50,000
Mason County, West Virginia:
7% Series A
due 2007 - June 1 - 50,000
5.45% Series B
due 2016 - December 1 50,000 -
Marshall County, West
Virginia:
6.95% Series A
due 2007 - December 1 - 50,000
7-1/4% Series B
due 2008 - June 1 - 35,000
5.45% Series B
due 2014 - July 1 50,000 -
5.90% Series D
due 2022 - April 1 35,000 -
6.85% Series C
due 2022 - June 1 50,000 50,000
Unamortized Discount (2,897) (2,358)
Total $232,103 $232,642
Under the terms of the installment purchase contracts, the Company is
required to pay amounts sufficient to enable the payment of interest on and
the principal (at stated maturities and upon mandatory redemption) of related
pollution control revenue bonds issued to finance the construction of
pollution control facilities at certain plants.
At December 31, 1993, annual consolidated long-term debt payments,
excluding premium or discount, are as follows:
Principal Amount
(in thousands)
1994 $ 5,397
1995 397
1996 56,166
1997 71,270
1998 72,739
Later Years 995,345
Total $1,201,314
Short-term debt borrowings are limited by provisions of the 1935 Act to
$200 million. Lines of credit are shared with AEP System companies and
at December 31, 1993 and 1992 were available in the amounts of $537 million
and $521 million, respectively. Commitment fees of approximately 3/16 of 1%
a year are paid to the banks to maintain the lines of credit. Outstanding
short-term debt consisted of $2.2 million of notes payable and $38 million of
commercial paper at December 31, 1993.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS:
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. At December 31, 1993 and 1992 fair
values for long-term debt were $1.25 billion and $1.41 billion, respectively.
Fair value for preferred stock subject to mandatory redemption, issued in
1993, is $112.6 million. 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.
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1993
March 31 $430,158 $68,965 $49,287
June 30 410,923 62,899 39,499
September 30 457,532 65,100 43,643
December 31 409,964 71,223 53,341
1992
March 31 439,537 67,778 41,624
June 30 394,739 53,288 26,641
September 30 436,914 62,703 38,573
December 31 420,407 68,002 53,715
Fourth quarter 1992 net income includes $15 million comprised of interest
on prior years federal income tax refunds, the resolution of the Martinka
mine fuel cost recovery litigation, discussed in Note 2, and cost reductions
due to favorable benefit plan experience.