OHIO POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
1997 1996 1995 1994 1993
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,965,818 $1,911,708 $1,822,997 $1,738,726 $1,708,577
Operating Expenses 1,689,425 1,614,547 1,550,837 1,493,853 1,440,390
Operating Income 276,393 297,161 272,160 244,873 268,187
Nonoperating Income 14,822 6,374 11,240 7,722 18,075
Income Before Interest
Charges 291,215 303,535 283,400 252,595 286,262
Interest Charges 82,526 85,880 93,953 89,969 100,492
Net Income 208,689 217,655 189,447 162,626 185,770
Preferred Stock
Dividend Requirements 2,647 8,778 14,668 15,301 16,990
Earnings Applicable to
Common Stock $ 206,042 $ 208,877 $ 174,779 $ 147,325 $ 168,780
December 31,
1997 1996 1995 1994 1993
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $5,155,797 $4,996,621 $4,915,222 $4,938,121 $4,802,327
Accumulated Depreciation
and Amortization 2,349,995 2,216,534 2,091,148 2,077,626 1,992,082
Net Electric Utility Plant $2,805,802 $2,780,087 $2,824,074 $2,860,495 $2,810,245
Total Assets $4,163,202 $4,092,166 $4,156,564 $4,151,140 $4,133,791
Common Stock and
Paid-in Capital $ 783,497 $ 781,863 $ 780,675 $ 784,301 $ 784,301
Retained Earnings 590,151 584,015 518,029 483,222 474,500
Total Common Shareholder's
Equity $1,373,648 $1,365,878 $1,298,704 $1,267,523 $1,258,801
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 17,542 $ 38,532 $ 41,240 $ 126,240 $ 126,240
Subject to Mandatory
Redemption (a) 11,850 109,900 115,000 115,000 115,000
Total Cumulative
Preferred Stock $ 29,392 $ 148,432 $ 156,240 $ 241,240 $ 241,240
Long-term Debt (a) $1,095,226 $1,069,729 $1,227,632 $1,188,989 $1,194,483
Obligations Under Capital
Leases (a) $ 157,487 $ 131,285 $ 131,926 $ 127,735 $ 97,329
Total Capitalization and
Liabilities $4,163,202 $4,092,166 $4,156,564 $4,151,140 $4,133,791
(a) Including portion due within one year.
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This discussion includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect assumptions, and involve
a number of risks and uncertainties. Among the factors that could
cause actual results to differ materially are: electric load and
customer growth; abnormal weather conditions; available sources and
costs of fuels and availability of generating capacity; the speed
and degree to which competition is introduced to our power
generation business, the terms of the transition to competition,
and its impact on rate structures; the ability to recover stranded
costs, new legislation and government regulations, the ability of
the Company to successfully reduce its costs; the economic climate
and growth in our service territory; inflationary trends, interest
rates and other risks.
Business Outlook
The Company's ability to recover its costs as the industry
transitions to competition and as customer choice is more broadly
available is the most significant factor affecting its future.
Competition in the wholesale generation market continues to
intensify since the adoption of federal legislation in 1992 which
gave wholesale customers the right to choose their energy supplier
and the Federal Energy Regulatory Commission (FERC) orders issued
in 1996 which forced open access transmission. The introduction of
competition and customer choice for retail customers has been slow
although activity has been increasing. Federal legislation has
been proposed to mandate competition and customer choice at the
retail level, and several states have introduced or are considering
similar legislation. Ohio is considering legislative initiatives
to move to customer choice, although the timing is uncertain. The
Company supports customer choice and is proactively involved in
discussions at both the state and federal levels regarding how best
to structure and transition to a competitive marketplace.
As the electric energy market evolves from cost-of-service
ratemaking to market-based pricing, many complex issues must be
resolved, including the recovery of stranded costs. While FERC
orders No. 888 and 889 provide, under certain conditions, for
recovery of stranded cost at the wholesale level, the issue of
stranded cost recovery is unresolved at the much larger retail
level. The amount of any stranded costs the Company may experience
depends on the timing and extent to which direct competition is
introduced to our business and the then-existing market price of
electricity.
Under the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71 "Accounting for the Effects of Certain
Types of Regulation," regulatory assets (deferred expenses) and
regulatory liabilities (deferred revenues) are included in the
consolidated balance sheets of cost-based regulated utilities in
accordance with regulatory actions to match expenses and revenues
with cost-based rates. In order to maintain net regulatory assets
(net expense deferrals) on the balance sheet, SFAS No. 71 requires
that rates charged to customers be cost-based and the recovery of
regulatory assets must be probable. In the event a portion of the
Company's business no longer meets the requirements of SFAS No. 71,
net regulatory assets would have to be written off for that portion
of the business. The provisions of SFAS No. 71 and SFAS No. 101
"Accounting for the Discontinuance of Application of Statement No.
71" never anticipated that deregulation would include an extended
transition period or that it would provide for recovery after the
transition period of stranded costs. In July 1997 the Emerging
Issues Task Force (EITF) of the Financial Accounting Standards
Board (FASB) reached a consensus that the application of SFAS No.
71 to a segment of a regulated electric utility which is subject to
a legislative plan to transition to competition in that segment
should cease when the legislation is passed, or an enabling rate
order is issued containing sufficient detail for the utility to
reasonably determine what the plan would entail. The EITF
indicated that the cessation of application of SFAS 71 would
require that existing regulatory assets and impaired plant be
written off unless they are recoverable.
Although FERC orders No. 888 and 889 provide for competition in
the firm wholesale market, that market is a relatively small part
of our business and most of our firm wholesale sales are still
under cost-of-service contracts. As a result the Company's
generation business is still cost-based regulated and should remain
so for the foreseeable future pending the passage of enabling state
legislation to deregulate the generation business. We believe that
enabling state legislation should provide for the recovery of any
generation-related net regulatory assets and other reasonable
stranded costs from impaired generation assets. We are working
with regulators, customers and legislators to provide for probable
recovery of these stranded costs during a transition period in
which rates are fixed or frozen and electric utilities would take
steps to achieve cost savings which would be used to reduce or
eliminate their stranded costs. However, if in the future the
Company's generation business were to no longer be cost-based
regulated and if it were not possible to demonstrate probability of
recovery of resultant stranded costs including regulatory assets,
results of operations, cash flows and financial condition of the
Company would be adversely affected.
Cost Containment and Process Improvements
Efforts continue to reduce the costs of products and services
in order to maintain our competitiveness. Prior to 1997, reviews
of our major processes led to decisions to consolidate in the
American Electric Power Service Corporation senior management and
certain functions and operations. Among the functions consolidated
in this restructuring were generation plant maintenance, system
operations, accounting and load research. While staff reductions
and cost savings are presently being achieved in these and other
areas, expenses for new marketing, customer services and modern
efficient management information systems are increasing to prepare
the Company for competition.
Process improvement efforts and expenditures to develop and
implement the new customer service system and similar efforts and
expenditures to acquire, install and enhance new client server
based accounting and budgeting/financial planning software should
produce further improvements and efficiencies, enabling the Company
to continue to offer its customers excellent service at competitive
prices.
Fuel Costs
We recognize that we must continue to manage our coal costs to
maintain our competitive position. Nearly all of the Company's
generation is coal fired and approximately 35% of the 20 million
tons of coal we burn is supplied by affiliated mines with the
remainder acquired under long-term contracts and purchases in the
spot market. As long-term contracts expire we are negotiating with
unaffiliated suppliers to lower coal costs. We intend to continue
to prudently supplement our long-term coal supplies with spot
market purchases as long as favorable spot market prices exist.
Affiliated Coal
In prior years we have agreed in our Ohio jurisdiction to
certain limitations on the recovery of affiliated coal costs. Our
analysis shows that we should be able to recover, through 2009,
the term of the agreement, the Ohio jurisdictional portion of the
costs of our affiliated mining operations including future mine
closure costs. Management expects to recover its non-Ohio
jurisdictional portion of the investment in and the liabilities and
closing costs of our affiliated mines estimated to be $102 million
after tax at December 31, 1997. However, should it become apparent
that these affiliated mining costs will not be recovered from Ohio
and/or non-Ohio jurisdictional customers, the mines may have to be
closed and future earnings, cash flows and possibly financial
condition could be adversely affected. In addition compliance with
Phase II requirements of the Clean Air Act Amendments of 1990 (CAAA),
which become effective in January 2000, could also cause the mining
operations to close. Unless the cost of any mine closure is
recovered either in regulated rates or as a stranded cost under a
plan to transition the generation business to competition, future
earnings, cash flows and possibly financial condition could be
adversely affected.
Environmental Concerns
We take great pride in our efforts to economically produce and
deliver electricity while minimizing the impact on the environment.
The Company has spent hundreds of millions of dollars to equip our
facilities with the latest economical clean air and water
technologies and to research possible new technologies. We intend
to continue to take a leadership role to foster economically
prudent efforts to protect and preserve the environment.
By-products from the generation of electricity include
materials such as ash, slag, and sludge. Coal combustion by-products
are typically disposed of or treated in captive disposal
facilities or are beneficially utilized. In addition, our
generating plants and transmission and distribution facilities have
used asbestos, PCBs and other hazardous and nonhazardous materials.
The Company is currently incurring costs to safely dispose of such
substances. Additional costs could be incurred to comply with new
laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and
Liability Act or Superfund addresses clean-up of hazardous
substances at disposal sites and authorized the United States
Environmental Protection Agency (Federal EPA) to administer the
clean-up programs. As of year-end 1997, the Company is currently
involved in litigation with respect to three sites overseen by the
Federal EPA, and has been named by the Federal EPA as a
"Potentially Responsible Party" (PRP) for two other sites. There
are three additional sites for which the Company has received
information requests which could lead to PRP designation. The
Company's liability has been resolved for a number of sites with no
significant effect on results of operations and present estimates
do not anticipate material cleanup costs for identified sites in
which we have been declared a PRP. However, if for reasons not
currently identified significant costs are incurred for cleanup,
future results of operations, cash flows and possibly financial
condition would be adversely affected unless the costs can be
recovered.
Federal EPA is required by the CAAA to issue rules to implement
the law. In December 1996 Federal EPA issued final rules governing
nitrogen oxide (NOx) emissions that must be met after January 1,
2000 (Phase II of the CAAA). The final rules will require
substantial reductions in NOx emissions from certain types of power
plant boilers including those in AEP's power plants. In December
1996 a group of utilities including AEP operating companies filed
a petition for review of the rules in a U.S. Court of Appeals and
requested expedited consideration of the appeal. In addition the
Federal EPA published proposed rulemaking requiring the revision of
state implementation plans in 22 eastern states, including Ohio and
West Virginia in which the Company has coal-fired generating
plants. The proposed rule will require reductions in NOx emissions
from utility sources of approximately 85% below 1990 levels and
entail very substantial capital and operating expenditures by AEP
System operating companies. Since the Company shares energy and
wholesale sales as a member of the AEP System Power Pool it is
affected by expenditures at the generating units of other
affiliated members of the AEP Pool. Pollution controls to meet the
proposed revised NOx emission limits would have to be in place by
2002. Also, the Federal EPA has been petitioned for a new
rulemaking by eight northeast states for the development of
controls for upwind sources. The costs to comply with the emission
reductions required by these Federal EPA actions is expected to be
substantial and would have a material adverse impact on future
results of operations, cash flows and possibly financial condition
if the resultant costs are not recovered from customers.
In 1997 the Federal EPA published a revised ambient air quality
standard for ozone and established a new ambient air quality
standard for fine particulate matter. These standards are expected
to result in redesignation of a number of areas of the country
currently in compliance with the existing standard to nonattainment
which could ultimately dictate more stringent emission restrictions
for the Company's generating units. Under the new rules the states
must first determine the attainment status of their areas. The
states then have three years to submit a compliance plan and up to
ten years after designation to come into compliance with the new
standards. The compliance deadline could be as late as 2010 for
the ozone standard and 2012-2015 for the fine particulate standard.
Although we are reviewing the impact of the new rules, we are
unable to estimate compliance costs without knowledge of the
reductions that Ohio will find necessary to meet the new standards.
If such reductions are significant and the Company and its
affiliates must bear a significant portion of the cost of
compliance in a region or county that is in violation of the
revised standards, it would have a material adverse effect on
results of operations, cash flows and possibly financial condition
unless such costs are recovered from customers.
At the global climate conference in Kyoto, Japan in December
1997 more than 160 countries negotiated a treaty limiting emissions
of greenhouse gases, chiefly carbon dioxide, which may eventually
contribute to global warming. Although there is no clear
scientific evidence that carbon dioxide contributes to global
warming and damages the environment, the treaty, which requires
Congressional approval, calls for a seven percent reduction below
emission levels of green house gases in 1990. We intend to work
with the Congress to insure that science and reason are introduced
to the debate. If approved by the Congress the costs to comply
with the emission reductions required by the Kyoto treaty are
expected to be substantial and would have a material adverse impact
on results of operations, cash flows and possibly financial condition
if not recovered from customers.
Results of Operations
Although operating revenues increased in 1997 due to increased
wholesale transactions from a new power marketing business, net
income declined $9 million or 4% largely due to a decline in retail
sales, price concessions granted to two major industrial customers
and the effects of the competitive nature of the wholesale power
market. In July of 1997 AEP started a new business of buying and
selling power outside the AEP System. The significant increase in
revenues was substantially offset by an increase in the related
purchased power expense. Net income increased 15% in 1996
primarily due to increased sales of energy and services and reduced
financing charges. The 1996 sales increase was due to increased
wholesale power sales to the Power Pool and unaffiliated utilities
and increased services provided to power marketers and other
utilities. Also contributing to the improvement in net income in
1996 were severance pay charges recorded in 1995 in connection with
AEP's restructuring of management and operations and gains recorded
in 1996 from emission allowance transactions.
Operating Revenues and Energy Sales Increase
Operating revenues increased 3% in 1997 primarily due to new
wholesale power marketing transactions which began in July. The 5%
increase in 1996 operating revenues reflects increased sales to
wholesale customers. The change in operating revenues in both
years is analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1997 1996
Amount % Amount %
Retail:
Price Variance. . . . . . . . . $ (7.9) $ 7.9
Volume Variance . . . . . . . . (12.8) 3.4
Fuel Cost Recoveries. . . . . . (12.3) 5.8
(33.0) (2.5) 17.1 1.3
Wholesale:
Price Variance. . . . . . . . . (10.8) (153.2)
Volume Variance . . . . . . . . 80.8 220.4
Fuel Cost Recoveries. . . . . . 0.4 1.7
70.4 13.4 68.9 15.1
Other Operating Revenues. . . . . 16.7 2.7
Total . . . . . . . . . . . . $ 54.1 2.8 $ 88.7 4.9
The decrease in 1997 retail revenues was due to price
concessions to two major industrial customers; reduced sales to
residential and industrial customers; and decreased fuel clause
revenues. Mild weather in 1997 reduced energy usage by residential
customers. Sales to industrial customers decreased due to a labor
dispute at a major industrial customer which idled its
manufacturing facilities from October 1, 1996 through most of the
third quarter of 1997. Pursuant to a Public Utilities Commission
of Ohio (PUCO) order, deferred emission allowance gains were
returned to retail customers through the fuel clause adjustment
mechanism in 1997. Retail revenues increased in 1996 due primarily
to a March 1995 increase in retail rates approved by the PUCO as
part of the Settlement Agreement which allowed recovery of CAAA
compliance costs. Revenues from residential and commercial
customers each increased 3% reflecting the rate increase.
Industrial customer revenues were flat as the positive effect of
the rate increase on revenues was offset by the effect of a
favorable adjustment recorded in June 1995 under a major industrial
contract. Growth in the number of residential and commercial
customers also contributed to the increase in retail operating
revenues.
Wholesale sales increased significantly in 1997 mainly due to
increased power sales from new power marketing transactions which
began in July 1997 and increased coal conversion services. The new
power marketing transactions involve the purchase and sale of power
outside the AEP transmission system. Coal conversion services
which began in 1996 are provided to power marketers and certain
non-affiliated utilities under a FERC approved interruptible tariff
for the conversion of customers' coal to electricity and do not
include any fuel cost. In 1996 wholesale revenues increased 15%
while sales increased 48%. The Company's share of Power Pool sales
increased 100% reflecting increased sales of coal conversion
services which resulted in 1.8 billion kilowatthours of electricity
being provided to power marketers and certain other utilities.
Since these sales are for the service of converting the customers'
coal to electricity and do not include any fuel cost, the average
wholesale price per kilowatt was significantly less in 1996 than in
1995. Wholesale power sales to the Power Pool increased 46%
reflecting increased weather-related demand of affiliated Power
Pool members in the first half of 1996 and the increased
availability of the Gavin Plant in 1996. Energy sales to the Power
Pool are priced to compensate the supplying Power Pool member for
its out-of-pocket costs. The Gavin units had been out-of-service
for extended periods during the first three months of 1995 while
the flue gas desulfurization systems (scrubbers) were being
installed and maintained.
The increase in other operating revenues in 1997 was primarily
due to increased transmission service for the delivery of power
between unaffiliated companies.
Operating Expenses Increase
Operating expenses increased by approximately 5% in 1997 and 4%
in 1996. The increase in 1997 was attributable to the Company's
share of power purchases by AEP's new power marketing business.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1997 1996
Amount % Amount %
Fuel. . . . . . . . . . . . . . . . . $(5.2) (0.8) $31.2 5.1
Purchased Power . . . . . . . . . . . 82.0 128.4 1.9 3.1
Other Operation . . . . . . . . . . . (0.5) (0.1) (4.5) (1.4)
Maintenance . . . . . . . . . . . . . (8.7) (5.7) 8.3 5.8
Depreciation and Amortization . . . . 3.0 2.2 2.0 1.4
Taxes Other Than Federal Income Taxes 0.5 0.3 (2.0) (1.2)
Federal Income Taxes. . . . . . . . . 3.8 3.1 26.8 28.0
Total Operating Expenses. . . . . . $74.9 4.6 $63.7 4.1
The increase in fuel expense in 1996 was due to a 7% increase
in generation to meet the increased demand for energy. The
increased availability of the Gavin units in 1996 compared with
1995 when the units were out of service for extended periods during
the first three months of 1995 for the installation and maintenance
of the scrubbers enabled the Company to increase generation.
Purchased power expense increased in 1997 primarily due to the
Company's share of purchases of power by AEP's new power marketing
business.
The decrease in maintenance expense in 1997 reflects decreased
boiler plant maintenance reflecting a reduction in planned
maintenance work on generating facilities. Maintenance expense
rose in 1996 as the level of maintenance activity went up
reflecting a full year's operation of the Gavin Plant scrubbers and
increased generation.
In 1996 federal income tax expense attributable to operations
increased primarily due to an increase in pre-tax operating income.
Interest Charges and Preferred Stock Dividends
Interest charges decreased in 1996 due to a reduction in the
average outstanding balance of long-term debt and a decrease in
carrying charges recorded on deferred gains on the sale of emission
allowances.
The reacquisition of 1.2 million shares of preferred stock
through a first quarter 1997 tender offer was primarily responsible
for the decrease in 1997 in preferred stock dividend requirements.
Financial Condition
In 1997 the Company maintained its strong financial condition.
We redeemed 1,190,395 shares of cumulative preferred stock with
rates ranging from 4.08% to 6.35% at a total cost of $118 million.
Part of the reacquired shares were reacquired under terms of a
tender offer in conjunction with a special shareholders' meeting at
which the articles of incorporation were revised to remove certain
capitalization ratio requirements that constrained the Company's
issuance of unsecured and short-term debt. The restrictions
limited our financial flexibility and could have placed us at a
competitive disadvantage in the future. We used short-term debt
and junior subordinated deferrable interest debentures to pay for
the preferred stock tendered and to benefit from the tax
deductibility of interest.
The Company issued $148 million principal amount of long-term
obligations in 1997 at interest rates ranging from 6.73% to 7.92%.
We continued to reduce financing costs in 1997, as evidenced by the
reduction in interest expense, by retiring higher-cost bonds and
restructuring the long-term debt from senior secured/first mortgage
bonds to senior unsecured debt and junior debentures. The
principal amount of long-term debt retirements, including
maturities, totaled $117 million with interest rates ranging from
6.5% to 8.75%. Our senior secured debt/first mortgage bond ratings
which were reaffirmed and improved in 1997, are: Moody's, A3;
Standard & Poor's, A-; Fitch, A-; and Duff & Phelps, A. The
Company's good bond ratings meet and often exceed the required
rating of bond investors. With higher bond ratings, the Company
attracts a wider investor base, a bigger share of capital in the
bond market and lower interest rates.
Gross plant and property additions were $226 million in 1997
and $145 million in 1996. Management estimates construction
expenditures for the next three years to be $577 million. The
funds for construction of new facilities and improvement of
existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred
stock issuances and investments in common equity by the Company's
parent, American Electric Power Company, Inc. However, all of the
construction expenditures for the next three years are expected to
be financed with internally generated funds. Allowance for funds
used during construction accruals declined in recent years
primarily due to the decrease in generation plant construction
combined with a decrease in interest rates. Inflation affects the
Company's cost of replacing utility plant and the cost of operating
and maintaining plant. The rate-making process generally limits
our recovery to the historical cost of assets resulting in economic
losses when the effects of inflation are not recovered from
customers on a timely basis. However, economic gains that result
from the repayment of long-term debt with inflated dollars partly
offset such losses.
When necessary the Company generally issues short-term debt to
provide for interim financing of capital expenditures that exceed
internally generated funds. At December 31, 1997, $442 million of
unused short-term lines of credit shared with other AEP System
companies were available. Short-term debt borrowings are limited
by provisions of the Public Utility Holding Company Act of 1935 to
$250 million. Generally periodic reductions of outstanding short-term
debt are made through issuances of long-term debt and through
additional capital contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds and
preferred stock. The minimum coverage ratios are 2.0 for mortgage
bonds and 1.5 for preferred stock. At December 31, 1997, the
mortgage bonds and preferred stock coverage ratios were 9.74 and
3.67, respectively.
Other Matters
Corporate Owned Life Insurance
In connection with the audit of AEP's consolidated federal
income tax returns the Internal Revenue Service (IRS) agents sought
a ruling from the IRS National Office that certain interest
deductions relating to a corporate owned life insurance (COLI)
program should not be allowed. The Company established the COLI
program in 1990 as part of its strategy to fund and reduce the cost
of medical benefits for retired employees. AEP filed a brief with
the IRS National Office refuting the agents' position. No
adjustments have been proposed by the IRS. However, should a
disallowance of the COLI interest deductions be proposed it would,
if sustained, reduce earnings by approximately $107 million
(including interest). Management believes it has meritorious
defenses and will vigorously contest any proposed adjustments. No
provisions for this amount have been recorded. In the event the
Company is unsuccessful it could have a material adverse impact on
results of operations and cash flows.
Computer Software - Year 2000 Compliance
Many existing computer hardware and software programs will not
properly recognize calendar dates beginning in the year 2000.
Unless corrected, this "Year 2000" problem may cause computer
malfunctions, such as system shutdowns or incorrect calculations
and system output. The Company is addressing the problem
internally by modifying or replacing its computer hardware and
software programs. The problem is also being addressed externally
with entities that interact electronically with the Company,
including but not limited to, suppliers, service providers,
government agencies, customers, creditors and financial service
organizations. However, due to the complexity of the problem and
the interdependent nature of computer systems, if the Company's
corrective actions, and/or the actions of other interdependent
entities, fail for critical applications, the Company may be
adversely impacted in the year 2000. Although significant, the
cost of correcting the "Year 2000" problem is not expected to have
a material impact on the results of operations, cash flows or
financial condition.
New Accounting Standards
In June 1997 the FASB issued SFAS No. 130 "Reporting
Comprehensive Income" and SFAS No. 131 "Disclosures About Segments
of an Enterprise and Related Information." SFAS No. 130
establishes the standards for reporting and displaying components
of "comprehensive income," which is the total of net income and all
other changes in equity except those resulting from investments by
shareholders and dispositions to shareholders. SFAS No. 131
initiates standards for reporting information about operating
segments in annual and interim financial statements as well as
related disclosures about products and services, geographic areas
and major customers. The adoption of these new reporting standards
in 1998 is not expected to have a material effect on the results of
operations, cash flows and/or financial condition.
Litigation
The Company is involved in a number of legal proceedings and
claims. While we are unable to predict the outcome of such
litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows and/or financial condition.
INDEPENDENT AUDITORS' REPORT
To the Shareholders 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, 1997 and
1996, and the related consolidated statements of income, retained
earnings, and cash flows for each of the three years in the period
ended December 31, 1997. These financial statements are the
responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of Ohio
Power Company and its subsidiaries as of December 31, 1997 and
1996, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1997 in
conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 24, 1998
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
1997 1996 1995
(in thousands)
OPERATING REVENUES $1,965,818 $1,911,708 $1,822,997
OPERATING EXPENSES:
Fuel 642,135 647,391 616,132
Purchased Power 145,861 63,862 61,945
Other Operation 322,088 322,567 327,026
Maintenance 143,831 152,495 144,202
Depreciation and Amortization 140,807 137,804 135,844
Taxes Other Than Federal Income Taxes 168,480 168,017 170,047
Federal Income Taxes 126,223 122,411 95,641
Total Operating Expenses 1,689,425 1,614,547 1,550,837
OPERATING INCOME 276,393 297,161 272,160
NONOPERATING INCOME 14,822 6,374 11,240
INCOME BEFORE INTEREST CHARGES 291,215 303,535 283,400
INTEREST CHARGES 82,526 85,880 93,953
NET INCOME 208,689 217,655 189,447
PREFERRED STOCK DIVIDEND REQUIREMENTS 2,647 8,778 14,668
EARNINGS APPLICABLE TO COMMON STOCK $ 206,042 $ 208,877 $ 174,779
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1997 1996 1995
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 208,689 $ 217,655 $ 189,447
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 172,186 164,485 154,915
Deferred Federal Income Taxes 7,627 18,682 29,573
Deferred Investment Tax Credits (3,487) (3,552) (3,570)
Deferred Fuel Costs (net) (34,548) (17,745) (26,213)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (62,371) (32,008) (41,631)
Fuel, Materials and Supplies (11,127) 18,151 7,451
Accrued Utility Revenues 1,266 1,248 (11,325)
Accounts Payable 95,348 (13,181) (19,852)
Other (net) 68,435 17,866 63,658
Net Cash Flows From Operating Activities 442,018 371,601 342,453
INVESTING ACTIVITIES:
Construction Expenditures (172,477) (113,481) (122,132)
Proceeds from Sales of Property and Other 8,954 8,756 4,241
Net Cash Flows Used For Investing Activities (163,523) (104,725) (117,891)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 146,590 - 82,331
Retirement of Cumulative Preferred Stock (117,624) (6,788) (86,917)
Retirement of Long-term Debt (122,127) (160,486) (44,348)
Change in Short-term Debt (net) 37,398 31,902 (7,835)
Dividends Paid on Common Stock (199,333) (142,856) (139,428)
Dividends Paid on Cumulative Preferred Stock (3,199) (8,645) (15,065)
Net Cash Flows Used For Financing Activities (258,295) (286,873) (211,262)
Net Increase (Decrease) in Cash and Cash Equivalents 20,200 (19,997) 13,300
Cash and Cash Equivalents January 1 24,003 44,000 30,700
Cash and Cash Equivalents December 31 $ 44,203 $ 24,003 $ 44,000
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1997 1996
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,606,981 $2,556,507
Transmission 837,953 820,636
Distribution 927,239 872,936
General (including mining assets) 709,475 680,443
Construction Work in Progress 74,149 66,099
Total Electric Utility Plant 5,155,797 4,996,621
Accumulated Depreciation and Amortization 2,349,995 2,216,534
NET ELECTRIC UTILITY PLANT 2,805,802 2,780,087
OTHER PROPERTY AND INVESTMENTS 113,925 106,485
CURRENT ASSETS:
Cash and Cash Equivalents 44,203 24,003
Accounts Receivable:
Customers 196,982 118,551
Affiliated Companies 55,597 69,412
Miscellaneous 43,594 44,771
Allowance for Uncollectible Accounts (2,501) (1,433)
Fuel - at average cost 119,543 113,361
Materials and Supplies - at average cost 80,853 75,908
Accrued Utility Revenues 37,586 38,852
Prepayments 36,611 44,203
TOTAL CURRENT ASSETS 612,468 527,628
REGULATORY ASSETS 523,891 540,123
DEFERRED CHARGES 107,116 137,843
TOTAL $4,163,202 $4,092,166
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
December 31,
1997 1996
(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 462,296 460,662
Retained Earnings 590,151 584,015
Total Common Shareholder's Equity 1,373,648 1,365,878
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,542 38,532
Subject to Mandatory Redemption 11,850 109,900
Long-term Debt 1,012,031 1,002,436
TOTAL CAPITALIZATION 2,415,071 2,516,746
OTHER NONCURRENT LIABILITIES 295,375 245,032
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 83,195 67,293
Short-term Debt 78,700 41,302
Accounts Payable - General 146,824 51,506
Accounts Payable - Affiliated Companies 37,923 37,893
Taxes Accrued 160,055 162,798
Interest Accrued 16,255 18,094
Obligations Under Capital Leases 30,307 24,153
Other 94,338 84,385
TOTAL CURRENT LIABILITIES 647,597 487,424
DEFERRED INCOME TAXES 723,172 738,626
DEFERRED INVESTMENT TAX CREDITS 42,821 46,308
DEFERRED CREDITS 39,166 58,030
COMMITMENTS AND CONTINGENCIES (Note 4)
TOTAL $4,163,202 $4,092,166
See Notes to Consolidated Financial Statements.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
1997 1996 1995
(in thousands)
Retained Earnings January 1 $584,015 $518,029 $483,222
Net Income 208,689 217,655 189,447
792,704 735,684 672,669
Deductions:
Cash Dividends Declared:
Common Stock 199,333 142,856 139,428
Cumulative Preferred Stock:
4.08% Series 91 189 204
4-1/2% Series 581 911 911
4.20% Series 127 235 252
4.40% Series 204 417 440
5.90% Series 961 2,587 2,655
6.02% Series 735 2,401 2,408
6.35% Series 500 1,905 1,905
7.60% Series - - 2,564
7-6/10% Series - - 2,564
8.04% Series - - 1,162
Total Dividends 202,532 151,501 154,493
Capital Stock Expense 21 168 147
Total Deductions 202,553 151,669 154,640
Retained Earnings December 31 $590,151 $584,015 $518,029
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, sale, purchase, transmission and distribution of
electric power and provides electric power to over 679,000 retail
customers in northwestern, east central, eastern and southern
sections of Ohio. Wholesale electric power is supplied to
neighboring utility systems, power marketers and the American
Electric Power (AEP) System Power Pool (Power Pool). As a member
of the AEP Power Pool and a signatory company to the American
Electric Power System (AEP System) Transmission Equalization
Agreement, OPCo's facilities are operated in conjunction with the
facilities of certain other AEP affiliated utilities as an
integrated system.
The Company has three wholly-owned coal-mining subsidiaries:
Central Ohio Coal Company, Southern Ohio Coal Company and Windsor
Coal Company which conduct mining operations at the Muskingum mine,
Meigs mine and Windsor mine, respectively. Substantially all coal
produced by the coal-mining subsidiaries is sold to the Company at
cost including a Securities and Exchange Commission (SEC) approved
return on investment.
Regulation
As a subsidiary of AEP Co., Inc., the Company 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 are
eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, the Company's
consolidated financial statements reflect the actions of regulators
that result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate
regulated. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain
Types of Regulation," regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) are recorded to reflect
the economic effects of regulation and to match expenses with
regulated revenues.
Use of Estimates
The preparation of these financial statements in conformity
with generally accepted accounting principles requires in certain
instances the use of estimates. Actual results could differ from
those estimates.
Utility Plant
Electric utility plant is stated at original cost and is
generally subject to first mortgage liens. Additions, major
replacements and betterments are added to the plant accounts.
Retirements of plant are deducted from the electric utility plant
in service account and deducted from accumulated depreciation
together with associated removal costs, net of salvage. 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 capitalized
and recovered through depreciation over the service life of utility
plant. It represents the estimated cost of borrowed and equity
funds used to finance construction projects. The amounts of AFUDC
for 1997, 1996 and 1995 were not significant.
Depreciation, Depletion and Amortization
Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of property,
other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production:
Steam-Fossil-Fired 3.4%
Hydroelectric-Conventional 2.7%
Transmission 2.3%
Distribution 4.0%
General 2.5%
Amounts to be used for demolition and removal of plant are
recovered through depreciation charges included in rates.
Depreciation, depletion and amortization of coal-mining assets is
provided over each asset's estimated useful life, ranging up to 30
years, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used
to amortize coal rights and mine development costs based on
estimated recoverable tonnages at a current average rate of $1.91
per ton. These costs are included in the cost of coal charged to
fuel expense.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments
with original maturities of three months or less.
Operating Revenues and Fuel Costs
Revenues include the accrual of electricity consumed but
unbilled at month-end as well as billed revenues. Changes in
retail fuel cost are deferred until reflected in revenues through
a PUCO fuel cost recovery mechanism. The PUCO approved a February
1995 Settlement Agreement between OPCo and certain other parties
which fixed the fuel cost recovery rate factor at 1.465 cents per
kwh through November of 1998. See Note 3. Wholesale jurisdictional
fuel cost changes are expensed and billed as incurred.
Income Taxes
The Company follows the liability method of accounting for
income taxes as prescribed by SFAS No. 109, "Accounting for Income
Taxes." Under the liability method, deferred income taxes are
provided for all temporary differences between book cost and tax
basis of assets and liabilities which will result in a future tax
consequence. Where the flow-through method of accounting for
temporary differences is reflected in rates, deferred income taxes
are recorded with related regulatory assets and liabilities in
accordance with SFAS No. 71.
Investment Tax Credits
Investment tax credits have been accounted for under the flow-through
method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis. Deferred investment tax credits are being amortized over
the life of the related plant investment.
Debt and Preferred Stock
Gains and losses on reacquisition of debt are deferred and
amortized over the remaining term of the reacquired debt in
accordance with rate-making treatment. If the debt is refinanced
the reacquisition costs are deferred and amortized over the term of
the replacement debt commensurate with their recovery in rates.
Debt discount or premium and expenses of debt issuances are
amortized over the term of the related debt, with the amortization
included in interest charges.
Redemption premiums paid to reacquire preferred stock are
included in paid-in capital and amortized to retained earnings
commensurate with their recovery in rates. The excess of par value
over costs of preferred stock reacquired is credited to paid-in
capital and amortized to retained earnings.
Other Property and Investments
Other property and investments are stated at cost.
2. EFFECTS OF REGULATION:
In accordance with SFAS No. 71 the consolidated financial
statements include regulatory assets (deferred expenses) and
regulatory liabilities (deferred income) recorded in accordance
with regulatory actions in order to match expenses and revenues
from cost-based rates. Regulatory assets are expected to be
recovered in future periods through the rate-making process and
regulatory liabilities are expected to reduce future cost
recoveries. Among other things, application of SFAS No. 71
requires that the Company's rates be cost-based regulated. The
Company has reviewed all the evidence currently available and
concluded that it continues to meet the requirements to apply SFAS
No. 71. In the event a portion of the Company's business no longer
meets those requirements, net regulatory assets would have to be
written off for that portion of the business and assets
attributable to that portion of the business would have to be
tested for possible impairment and if required an impairment loss
recorded unless the net regulatory assets and impairment losses are
recoverable as a stranded investment.
Recognized regulatory assets and liabilities are comprised of
the following:
December 31,
1997 1996
(In Thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $383,887 $412,946
Deferred Fuel Costs 61,838 28,538
Unamortized Loss On
Reacquired Debt 16,229 18,022
Other 61,937 80,617
Total Regulatory Assets $523,891 $540,123
Regulatory Liabilities:
Deferred Investment Tax Credits $42,821 $46,308
Deferred Gains From Emission
Allowance Sales* 25,895 39,706
Other* 6,982 10,034
Total Regulatory Liabilities $75,698 $96,048
*Included in Deferred Credits on Consolidated Balance Sheets.
3. RATE MATTERS:
Recovery of Fuel Costs
Under the terms of a 1992 stipulation agreement the cost of
coal burned at the Gavin Plant is subject to a 15-year
predetermined price of $1.575 per million Btu's with quarterly
escalation adjustments through November 2009. A 1995 Settlement
Agreement set the fuel component of the electric fuel
component (EFC) factor at 1.465 cents per kwh for the period June
1, 1995 through November 30, 1998. The stipulation and settlement
agreements provide OPCo with the opportunity to recover over the
term of the stipulation agreement the Ohio jurisdictional share of
OPCo's investment in and the liabilities and future shutdown costs
of its affiliated mines as well as any fuel costs incurred above
the predetermined rate to the extent the actual cost of coal burned
at the Gavin Plant is below the predetermined prices. After full
recovery of these costs or November 2009, whichever comes first,
the price that OPCo can recover for coal from its affiliated Meigs
mine which supplies the Gavin Plant will be limited to the lower of
cost or the then-current market price. Pursuant to these
agreements the Company has deferred for future recovery $61 million
at December 31, 1997.
Based on the estimated future cost of coal burned at Gavin
Plant, management believes that the Ohio jurisdictional portion of
the investment in and liabilities and closing costs of the
affiliated mining operations including deferred amounts will be
recovered under the terms of the predetermined price agreement.
Management expects 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
buyouts, reclamation costs and employee benefits is estimated to be
approximately $102 million after tax at December 31, 1997.
The affiliated Muskingum and Windsor mines may have to close
by January 2000 in order to comply with the Phase II requirements
of the Clean Air Act Amendments of 1990 (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 the cost of affiliated coal
production and/or future shutdown costs of the Meigs, Muskingum and
Windsor mines can be recovered, results of operations, cash flows
and possibly financial condition would be adversely affected.
4. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
our utility operations. Such commitments do not include any
expenditures for new generating capacity. Aggregate construction
program expenditures for 1998-2000 are estimated to be $577
million.
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 PUCO's
review and approval, for deferral and subsequent recovery or refund
of changes in the cost of fuel. (See Note 3 for changes in the
fuel clause mechanism resulting from the Settlement and Stipulation
Agreements.) The unaffiliated 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.
Revised Air Quality Standards
On July 18, 1997, the United States Environmental Protection
Agency published a revised National Ambient Air Quality Standard
(NAAQS) for ozone and a new NAAQS for fine particulate matter (less
than 2.5 microns in size). The new ozone standard is expected to
result in redesignation of a number of areas of the country that
are currently in compliance with the existing standard to
nonattainment status which could ultimately dictate more stringent
emission restrictions for AEP System generating units. New
stringent emission restrictions on AEP System generating units to
achieve attainment of the fine particulate matter standard could
also be imposed. The AEP System operating companies joined with
other utilities to appeal the revised NAAQS and filed petitions for
review in August and September 1997 in the U.S. Court of Appeals
for the District of Columbia Circuit. Management is unable to
estimate compliance costs without knowledge of the reductions that
may be necessary to meet the new standards. If such costs are
significant, they could have a material adverse effect on results
of operations, cash flows and possibly financial condition unless
recovered.
Litigation
The Company is involved in a number of legal proceedings and
claims. While management is unable to predict the outcome of
litigation, it is not expected that the resolution of these matters
will have a material adverse effect on the results of operations,
cash flows or financial condition.
5. RELATED PARTY TRANSACTIONS:
Benefits and costs of the System's generating plants are shared
by members of the Power Pool. The Company is a member 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 also 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 capacity credits from the Power Pool.
Operating revenues includes revenues for capacity and energy
supplied to the Power Pool as follows:
Year Ended December 31,
1997 1996 1995
(In Thousands)
Capacity Revenues $165,604 $158,599 $147,317
Energy Revenues 149,436 152,909 132,604
Total $315,040 $311,508 $279,921
Purchased power expense includes charges of $26.4 million in
1997, $31.1 million in 1996 and $26.6 million in 1995 for energy
received from the Power Pool.
Power Pool members share in wholesale sales to unaffiliated
entities made by the Power Pool. The Company's share of the Power
Pool's wholesale sales included in operating revenues were $179.1
million in 1997, $106.1 million in 1996 and $94 million in 1995.
In addition, the Power Pool purchases power from unaffiliated
companies for resale to other unaffiliated entities. The Company's
share of these purchases was included in purchased power expense
and totaled $95.6 million (including new power marketing
transactions) in 1997, $11.8 million in 1996 and $15.6 million in
1995. Revenues from these transactions, including a transmission
fee for power that passes through the AEP System transmission
network, are included in the above Power Pool wholesale operating
revenues.
Purchased power expense includes $6.2 million in 1997, $5
million in 1996 and $2.9 million in 1995 for energy bought from the
Ohio Valley Electric Corporation, an affiliated company that is not
a member of the Power Pool.
Operating revenues include energy sold directly to Wheeling
Power Company (WPCo) in the amounts of $55.0 million in 1997, $57.1
million in 1996 and $55.2 million in 1995. WPCo 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 since the
Company's relative investment in transmission facilities is greater
than its relative peak demand, other operation expense includes
equalization charges of $10.5 million, $12.5 million and $13.7
million in 1997, 1996 and 1995, respectively.
Coal-transportation costs paid to affiliated companies aggre-
gate approximately $8.5 million, $8.6 million and $4.3 million in
1997, 1996 and 1995, respectively. These charges are included in
fuel expense. The prices charged by the affiliates for coal
transportation services are computed in accordance with orders
issued by the SEC.
The Company and an affiliate, Appalachian Power Company,
jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership
interests. The Company's share of these costs is included in the
appropriate expense accounts on the Consolidated Statements of
Income and the investment is included in electric utility plant on
the Consolidated Balance Sheets.
American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies. The costs of the services are billed 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 System
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. Pension costs are allocated by first charging each
participating AEP 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 required contribution in accordance
with the Employee Retirement Income Security Act of 1974. The
Company's share of net pension cost of the AEP System pension plan
for the years ended December 31, 1997, 1996 and 1995 was $1.4
million, $4.1 million and $2.4 million, respectively.
Postretirement Benefits Other Than Pensions (OPEB)
The AEP System provides certain other benefits for retired
employees. Substantially all non-UMWA employees are eligible for
postretirement health care and life insurance if they retire from
active service after reaching age 55 and have at least 10 service
years.
Postretirement medical benefits for UMWA employees who have or
will retire after January 1, 1976 are the liability of the coal-mining
subsidiaries. Eligibility for postretirement medical
benefits is based on retirement from active service after reaching
age 55 with at least 10 service years. In addition, non-active
UMWA employees will become eligible at age 55 if they have had 20
service years.
The funding policy for OPEB cost is to make contributions to
an external Voluntary Employees Beneficiary Association trust fund
equal to the incremental OPEB costs (i.e., the amount that the
total postretirement benefits cost under SFAS No. 106, "Employers
Accounting for Postretirement Benefits Other Than Pensions,"
exceeds the pay-as-you-go amount). Contributions were $11.4
million in 1997, $14.6 million in 1996, and $11.7 million in 1995.
OPEB costs are determined by the application of AEP System
actuarial assumptions to each company's employee complement. The
Company's annual accrued costs for 1997, 1996 and 1995 required by
SFAS 106 for employees and retirees were $30.1 million, $32.1
million and $35 million, respectively.
With the issuance of SFAS No. 106, the Company received
regulatory authority to defer the increased OPEB costs resulting
from the SFAS 106 required change from pay-as-you-go to accrual
accounting which were not being recovered in rates. The deferred
amounts are being amortized over a 4-year period ending in March
1999. At December 31, 1997 and 1996, $6 million and $10.9 million,
respectively, of OPEB costs were deferred.
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 Co., Inc. 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 Co., Inc. common stock.
The employer's annual contributions totaled $4 million in 1997 and
1996 and $4.4 million in 1995.
Other UMWA Benefits - The Company provides UMWA pension, health and
welfare benefits for certain employees, retirees, and their
survivors who meet eligibility requirements. The benefits are
administered by UMWA trustees and contributions are made to their
trust funds. Contributions based on hours worked are expensed as
paid as part of the cost of active mining operations and were not
material in 1997, 1996 and 1995. Based upon the UMWA actuarial
estimate the Company's share of the unfunded pension liability was
$6.7 million at June 30, 1997. In the event the Company should
significantly reduce or cease mining operations or contributions to
the UMWA trust funds, a withdrawal obligation will be triggered for
both the pension and health and welfare plans. If the mining
operations had been closed on December 31, 1997 the estimated
withdrawal liability for all UMWA benefits plans would have been
$6.7 million.
7. COMMON SHAREHOLDER'S EQUITY:
Mortgage indentures, 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, 1997, $20.8 million of retained earnings
were restricted. Regulatory approval is required to pay dividends
out of paid-in capital.
In 1997, 1996 and 1995 net changes to paid-in capital of $1.6
million, $1.2 million and $(3.6) million, respectively, represented
gains and expenses associated with cumulative preferred stock
transactions.
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1997 1996 1995
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $116,795 $102,406 $67,513
Deferred 11,257 21,835 29,960
Deferred Investment Tax Credits (1,829) (1,830) (1,832)
Total 126,223 122,411 95,641
Charged (Credited) to Nonoperating Income (net):
Current 624 (293) 183
Deferred (3,630) (3,153) (387)
Deferred Investment Tax Credits (1,658) (1,722) (1,738)
Total (4,664) (5,168) (1,942)
Total Federal Income Taxes as Reported $121,559 $117,243 $93,699
The following is a reconciliation of the difference between the
amount of federal income taxes computed by multiplying book income
before federal income taxes by the statutory tax rate, and the
amount of federal income taxes reported.
Year Ended December 31,
1997 1996 1995
(in thousands)
Net Income $208,689 $217,655 $189,447
Federal Income Taxes 121,559 117,243 93,699
Pre-tax Book Income $330,248 $334,898 $283,146
Federal Income Taxes on Pre-tax Book Income at
Statutory Rate (35%) $115,587 $117,214 $99,101
Increase (Decrease) in Federal Income Taxes
Resulting From the Following Items:
Depreciation 15,961 13,394 14,250
Removal Costs (5,040) (5,775) (5,775)
Corporate Owned Life Insurance (7,179) (3,735) (8,415)
Investment Tax Credits (net) (3,487) (3,552) (3,453)
Other 5,717 (303) (2,009)
Total Federal Income Taxes as Reported $121,559 $117,243 $93,699
Effective Federal Income Tax Rate 36.8% 35.0% 33.1%
The following tables show the elements of the net deferred tax
liability and the significant temporary difference giving rise to
such deferrals:
December 31,
1997 1996
(in thousands)
Deferred Tax Assets $ 167,816 $ 161,409
Deferred Tax Liabilities (890,988) (900,035)
Net Deferred Tax Liabilities $(723,172) $(738,626)
Property Related Temporary
Differences $(619,067) $(621,254)
Amounts Due From Customers For
Future Federal Income Taxes (127,445) (135,281)
Deferred State Income Taxes (20,515) (21,337)
All Other (net) 43,855 39,246
Total Net Deferred
Tax Liabilities $(723,172) $(738,626)
The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliated
companies 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 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 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 1996 are presently open and under audit by the IRS.
During the audit the IRS agents requested a ruling from their
National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed. The COLI program was established in 1990 as part
of the Company's strategy to fund and reduce the cost of medical
benefits for retired employees. AEP filed a brief with the IRS
National Office refuting the agent's position. Although no
adjustments have been proposed, a disallowance of the COLI interest
deductions through December 31, 1997 would reduce earnings by
approximately $107 million (including interest). Management
believes it has meritorious defenses and will vigorously contest
any proposed adjustments. No provisions for this amount have been
recorded. In the event the Company is unsuccessful it could have
a material adverse impact on results of operations and cash flows.
9. LEASES:
Leases of property, plant and equipment are for periods of 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 for both operating and capital leases are
generally charged to operating expenses in accordance with rate-making
treatment. The components of rental costs are as follows:
Year Ended December 31,
1997 1996 1995
(in thousands)
Operating Leases $62,260 $64,891 $61,979
Amortization of
Capital Leases 25,275 23,217 24,467
Interest on
Capital Leases 9,445 8,473 8,528
Total Rental Costs $96,980 $96,581 $94,974
Properties under capital leases and related obligations on the
Consolidated Balance Sheets are as follows:
December 31,
1997 1996
(in thousands)
Electric Utility Plant:
Production $ 23,098 $ 21,689
General (including mining assets) 211,380 184,489
Total Electric Utility Plant 234,478 206,178
Accumulated Amortization 86,501 82,973
Net Electric Utility Plant 147,977 123,205
Other Property (net) 9,510 8,080
Net Property under
Capital Leases $157,487 $131,285
Obligations under Capital Leases:*
Noncurrent Liability $127,180 $107,132
Liability Due Within One Year 30,307 24,153
Total Capital Lease Obligations $157,487 $131,285
*Represents the present value of future minimum lease payments.
Noncurrent capital lease obligations are included in other
noncurrent liabilities in the Consolidated Balance Sheets.
Properties under operating leases and related obligations are
not included in the Consolidated Balance Sheets.
Future minimum lease rentals consisted of the following at
December 31, 1997:
Non-Cancelable
Capital Operating
Leases Leases
(in thousands)
1998 $ 38,620 $ 57,083
1999 33,638 54,986
2000 29,049 54,388
2001 23,370 53,995
2002 14,688 53,726
Later Years 54,926 455,851
Total Future Minimum
Lease Rentals 194,291 $730,029
Less Estimated
Interest Element 36,804
Estimated Present Value
of Future Minimum
Lease Rentals $157,487
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1997, 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.
In 1995 the Company redeemed and canceled all of the
outstanding shares of the following series of cumulative preferred
stock not subject to mandatory redemption: 7.60%, 350,000 shares;
7-6/10%, 350,000 shares; and 8.04%, 150,000 shares.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1997 Value Year Ended December 31, December 31, 1997 1997 1996
1997 1996 1995 (in thousands)
4.08% $103 $100 27,182 7,425 - 15,393 $ 1,539 $ 4,258
4-1/2% 110 100 97,949 - - 104,454 10,446 20,240
4.20% 103.20 100 28,875 8,025 - 23,100 2,310 5,198
4.40% 104 100 55,889 11,637 - 32,474 3,247 8,836
$17,542 $38,532
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Number of Shares Redeemed Outstanding December 31,
Series (a) Value Year Ended December 31, December 31, 1997 1997 1996
1997 1996 1995 (in thousands)
5.90% (b) $100 321,500 46,000 - 82,500 $ 8,250 $ 40,400
6.02% (c) 100 364,000 5,000 - 31,000 3,100 39,500
6.35% (c) 100 295,000 - - 5,000 500 30,000
$11,850 $109,900
(a) Not callable until after 2002. The sinking fund provisions of
each series have been met by the purchase of shares in advance of
the due date.
(b) 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. Shares previously redeemed may be applied to meet
sinking fund requirements.
(c) Commencing in 2003 and continuing through 2007 the Company may
redeem at $100 per share 20,000 shares of the 6.02% series and
5,000 shares of the 6.35% series outstanding under sinking fund
provisions at its option and all remaining outstanding shares must
be redeemed in 2008. Shares previously redeemed may be applied to
meet the sinking fund requirement.
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1997 1996
(in thousands)
First Mortgage Bonds $ 568,343 $ 664,429
Installment Purchase
Contracts 232,598 232,474
Senior Unsecured Notes 47,722 -
Notes Payable 61,681 81,681
Junior Debentures 131,620 82,475
Other 53,262 8,670
1,095,226 1,069,729
Less Portion Due Within
One Year 83,195 67,293
Total $1,012,031 $1,002,436
First mortgage bonds outstanding were as follows:
December 31,
1997 1996
(in thousands)
% Rate Due
6-1/2 1997 - August 1 $ - $ 46,620
6-3/4 1998 - March 1 55,661 55,661
8.10 2002 - February 15 50,000 50,000
8.25 2002 - March 15 50,000 50,000
6.75 2003 - April 1 40,000 40,000
6.875 2003 - June 1 40,000 40,000
6.55 2003 - October 1 40,000 40,000
6.00 2003 - November 1 25,000 25,000
6.15 2003 - December 1 50,000 50,000
8.80 2022 - February 10 50,000 50,000
8.75 2022 - June 1 - 50,000
7.75 2023 - April 1 40,000 40,000
7.85 2023 - June 1 40,000 40,000
7.375 2023 - October 1 40,000 40,000
7.10 2023 - November 1 25,000 25,000
7.30 2024 - April 1 25,000 25,000
Unamortized Discount (net) (2,318) (2,852)
568,343 664,429
Less Portion Due Within
One Year 55,661 46,620
Total $512,682 $617,809
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.
Installment purchase contracts have been entered into in
connection with the issuance of pollution control revenue bonds by
governmental authorities as follows:
December 31,
1997 1996
(in thousands)
Ohio Air Quality Development
7.4% Series B
due 2009 - August 1 $ 50,000 $ 50,000
Mason County, West Virginia:
5.45% Series B
due 2016 - December 1 50,000 50,000
Marshall County, West
Virginia:
5.45% Series B
due 2014 - July 1 50,000 50,000
5.90% Series D
due 2022 - April 1 35,000 35,000
6.85% Series C
due 2022 - June 1 50,000 50,000
Unamortized Discount (2,402) (2,526)
Total $232,598 $232,474
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.
The senior unsecured notes are due November 1, 2004 and their
interest rate is 6.73%.
Notes payable outstanding are as follows:
December 31,
% Rate Due 1997 1996
(in thousands)
7.19 1997 - January 29 $ - $20,000
6.85 1998 - January 29 16,681 16,681
Variable(a) 1999 - January 31 15,000 15,000
6.20 2001 - January 31 5,000 5,000
6.20 2001 - January 31 7,000 7,000
6.20 2001 - January 31 18,000 18,000
61,681 81,681
Less Portion Due Within One Year 16,681 20,000
Total $45,000 $61,681
(a) The rate at December 31, 1997 was 6.2625%.
Junior debentures outstanding were as follows:
December 31,
1997 1996
(in thousands)
8.16% Series A
due 2025 - September 30 $ 85,000 $85,000
7.92% Series B
due 2027 - March 31 50,000 -
Unamortized Discount (3,380) (2,525)
Total $131,620 $82,475
Interest may be deferred and payment of principal and interest
on the junior debentures is subordinated and subject in right to
the prior payment in full of all senior indebtedness of the
Company.
Finance obligations were entered into by the Company's coal
mining subsidiaries for mining facilities and equipment through
sale and leaseback transactions. In accordance with SFAS 98, the
transactions did not qualify as sale and leasebacks for accounting
purposes and therefore are shown as other long-term debt. The
terms on these long-term debt obligations are up to 20 years
including renewals, and contain bargain purchase options at
expiration of the agreements. At December 31, 1997 the interest
rates range from 6.61% to 6.98%.
At December 31, 1997, future long-term debt payments are as
follows:
Amount
(in thousands)
1998 $ 83,195
1999 26,575
2000 12,325
2001 43,077
2002 100,570
Later Years 837,862
Total Principal Amount 1,103,604
Unamortized Discount (8,378)
Total $1,095,226
Short-term debt borrowings are limited by provisions of the
1935 Act to $250 million. Lines of credit are shared with other
AEP System companies and at December 31, 1997 and 1996 were
available in the amounts of $442 million and $409 million,
respectively. Facility fees of approximately 1/10 of 1% of the
short-term lines of credit are required to maintain the lines of
credit. Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1997:
Notes Payable $10,700 6.6%
Commercial Paper 68,000 6.7
Total $78,700 6.7
December 31, 1996:
Notes Payable $ 4,600 5.4%
Commercial Paper 36,702 7.2
Total $41,302 7.0
12. 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.
Fair values for preferred stock subject to mandatory redemption
were $12.5 million and $109.7 million and for long-term debt were
$1.136 billion and $1.08 billion at December 31, 1997 and 1996,
respectively. The carrying amounts for preferred stock subject to
mandatory redemption were $11.9 million and $109.9 million and for
long-term debt were $1.095 billion and $1.07 billion at December
31, 1997 and 1996, respectively. Fair values are based on quoted
market prices for the same or similar issues and the current
dividend or interest rates offered for instruments of the same
remaining maturities.
13. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1997 1996 1995
(in thousands)
Cash was paid for:
Interest (net of
capitalized
amounts) $ 81,594 $ 85,769 $93,126
Income Taxes 127,719 105,035 65,629
Noncash Acquisitions
Under Capital Leases 53,389 30,942 31,799
14. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1997
March 31 $484,300 $80,531 $65,591
June 30 447,147 69,092 50,319
September 30 486,398 69,116 50,671
December 31 547,973 57,654 42,108
1996
March 31 504,741 87,844 66,536
June 30 449,383 67,283 43,949
September 30 483,957 69,252 54,920
December 31 473,627 72,782 52,250