IMP 1997 ANNUAL REPORT
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
1997 1996 1995 1994 1993
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,391,917 $1,328,493 $1,283,157 $1,251,309 $1,202,643
Operating Expenses 1,184,129 1,108,076 1,077,434 1,029,340 992,485
Operating Income 207,788 220,417 205,723 221,969 210,158
Nonoperating Income
(Loss) 4,415 2,729 6,272 7,428 (234)
Income Before Interest
Charges 212,203 223,146 211,995 229,397 209,924
Interest Charges 65,463 65,993 70,903 71,895 80,580
Net Income 146,740 157,153 141,092 157,502 129,344
Preferred Stock
Dividend Requirements 5,736 10,681 11,791 11,681 14,256
Earnings Applicable to
Common Stock $ 141,004 $ 146,472 $ 129,301 $ 145,821 $ 115,088
December 31,
1997 1996 1995 1994 1993
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,514,497 $4,377,669 $4,319,564 $4,269,306 $4,290,957
Accumulated
Depreciation and
Amortization 1,973,937 1,861,893 1,751,965 1,659,940 1,714,829
Net Electric Utility
Plant $2,540,560 $2,515,776 $2,567,599 $2,609,366 $2,576,128
Total Assets $3,967,798 $3,897,484 $3,928,337 $3,878,035 $3,723,648
Common Stock and
Paid-in Capital $ 789,056 $ 787,856 $ 787,686 $ 790,234 $ 790,625
Retained Earnings 278,814 269,071 235,107 216,658 177,638
Total Common
Shareholder's Equity $1,067,870 $1,056,927 $1,022,793 $1,006,892 $ 968,263
Cumulative Preferred
Stock:
Not Subject to
Mandatory
Redemption $ 9,435 $ 21,977 $ 52,000 $ 52,000 $ 87,000
Subject to Mandatory
Redemption (a) 68,445 135,000 135,000 135,000 100,000
Total Cumulative
Preferred Stock $ 77,880 $ 156,977 $ 187,000 $ 187,000 $ 187,000
Long-term Debt (a) $1,049,237 $1,042,104 $1,040,101 $1,069,887 $1,073,154
Obligations Under
Capital Leases (a) $ 195,227 $ 130,965 $ 142,506 $ 152,589 $ 98,753
Total Capitalization
and Liabilities $3,967,798 $3,897,484 $3,928,337 $3,878,035 $3,723,648
(a) Including portion due within one year.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
This report includes forward-looking statements within the
meaning of Section 21E of the Securities Exchange Act of 1934.
These forward-looking statements reflect numerous 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 cost of fuel and availability of generating capacity;
the speed and degree to which competition enters the power
generation, wholesale and retail sectors of the electric utility
industry; state and federal regulatory initiatives that increase
competition, threaten cost and investment recovery, and impact rate
structures; the ability of the Company to successfully reduce its
cost structure; the economic climate and growth in the service
territory; inflationary trends and 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 force 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. The Michigan Commission has started a program
for certain utilities to phase-in to competition with the objective
of providing full customer choice by 2002. The Company has begun
discussions with the Commission and other interested parties to
formulate a plan. The actions by the Michigan commission were not
mandated by legislation and are subject to a number of
uncertainties and it is not possible to determine what impact if
any the resolution of these matters will have on the operations of
the Company. The Company's Michigan jurisdiction accounts for 12%
of total revenues. Indiana 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 state
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 met 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 No. 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 near future pending the passage of enabling state
legislation to deregulate the generation business. We believe that
enabling state legislation should provide for the recovery of any
generation-related net regulatory assets and other reasonable
stranded costs from impaired generation assets. We are working
with regulators, customers and legislators to provide for recovery
of these stranded costs during a transition period in which rates
are fixed or frozen and electric utilities would take steps to
achieve cost savings which would be used to reduce or eliminate
their stranded costs. However, if in the future 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 Improvement
Efforts continue to reduce the cost 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 AEP
Service Corporation senior management and certain functions and
operations. While staff reductions and cost savings are presently
being achieved from the consolidation and restructuring expenses
for new marketing, customer services and modern efficient
management information systems are increasing to prepare for
competition.
In 1997, the Company began installing a new unified customer
service system which is designed to support the request for
service, billings, accounts receivable, credit and collection
functions. The new unified customer service system replaces a 30-year-old
customer system and a nine-year-old transmission and
distribution work management system. Process improvement efforts
and expenditures to develop and implement the new customer service
system and similar efforts and expenditures to acquire, install and
enhance new client server based accounting and budgeting/financial
planning software should produce further improvements and
efficiencies, enabling the Company to continue to offer its
customers excellent service at competitive prices.
Nuclear Cost
Significant efforts have been made to enhance our competitiveness
in nuclear power generation and to improve our nuclear
organizational efficiency. We continue to receive the "excellence
in performance" award from the Institute of Nuclear Power
Operations. Nuclear power plants have a major future financial
commitment to safely dispose of spent nuclear fuel and radioactive
plant components (i.e. to decommission the plant). It is difficult
to reduce nuclear generation costs since certain major cost
components are impacted by federal laws and Nuclear Regulatory
Commission (NRC) regulations.
The Nuclear Waste Policy Act of 1982 established federal
responsibility for the permanent off-site disposal of spent nuclear
fuel and high-level radioactive waste. By law we participate in
the Department of Energy's (DOE's) Spent Nuclear Fuel (SNF)
disposal program which is described in Note 3 of the Notes to
Consolidated Financial Statements. Since 1983 our customers have
paid $272 million for the disposal of spent nuclear fuel consumed
at the Cook Nuclear Plant. Under the provisions of the Nuclear
Waste Policy Act, collections from customers are to provide the DOE
with money to build a repository for spent fuel. To date the
federal government has not made sufficient progress towards a
permanent repository or otherwise assuming responsibility for SNF.
As long as there is a delay in the construction of a government
approved storage repository for SNF, the cost of both temporary and
permanent storage will continue to increase. The cost to
decommission the Cook Nuclear Plant is affected by both NRC
regulations and the DOE's SNF disposal program. Studies completed
in 1997 estimate the cost to decommission the Cook Nuclear Plant
range from $700 million to $1.152 billion in 1997 dollars. This
estimate could escalate due to uncertainty in the DOE's SNF
disposal program and the length of time that SNF may need to be
stored at the plant site delaying decommissioning. Presently we
are recovering the estimated cost of decommissioning the Cook
Nuclear Plant over its remaining life. However, the Company's
future results of operations and possibly its financial condition
could be adversely affected if the cost of spent nuclear fuel
disposal and decommissioning continues to increase and cannot be
recovered.
On September 9 and 10, 1997, during a NRC architect engineer
design inspection, questions regarding the operability of certain
safety systems caused Company operations personnel to shut down
Units 1 and 2 of the Cook Nuclear Plant. On September 19, 1997,
the NRC issued a Confirmatory Action Letter requiring the Company
to address the issues identified in the letter. The Company is
working with the NRC to resolve these issues and other issues
related to restart of the units. Certain issues identified in the
letter have been addressed. At this time management is unable to
determine when the units will be returned to service. If the units
are not returned to service in a reasonable period of time, it
could have an adverse impact on results of operations, cash flows
and possibly financial condition.
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, sludge, low-level radioactive waste
and spent nuclear fuel. 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,
polychlorinated biphenyls (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 (CERCLA or Superfund) addresses clean-up of hazardous
substances at disposal sites and authorized the United States
Environmental Protection Agency (Federal EPA) to administer the
clean-up programs. As of year-end 1997, the Company is currently
involved in litigation with respect to two sites overseen by the
Federal EPA, and has been named by the Federal EPA as a
"Potentially Responsible Party" (PRP) for three other sites. There
are four additional sites for which the Company has received
information requests which could lead to PRP designation as well as
information requests for one state administered site. 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 for
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.
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 AEP generating units including those of the Company's. 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 the states 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 greenhouse 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 $63 million or 5% in 1997
due to increased accruals for retail power costs that will be
collected in the future under power supply cost recovery mechanisms
and increased wholesale transactions from a new power marketing
business, net income decreased $10 million or 7% as a result of
increases in purchased power and other operation expenses. In July
1997 the Company started a new power marketing business of buying
and selling power outside the AEP System which accounted for the
increases in purchased power and wholesale revenues. The increase
in other operation expense reflects the effect of the recognition
of gains on sales of emission allowance in 1996 and higher
administrative and general costs and uncollectible accounts
expenses in 1997. In 1996 net income increased $16 million or 11%
mainly due to increased wholesale sales, a reduction in maintenance
expense and reduced financing costs. Also contributing to the
earnings increase 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 Increase
Operating revenues increased 4.8% in 1997 following a 3.5%
increase in 1996. The following analyzes the changes in operating
revenues:
Increase (Decrease)
From Previous Year
(dollars in millions) 1997 1996
Amount % Amount %
Retail:
Price Variance $ 26.6 $(25.9)
Volume Variance 7.4 32.8
34.0 3.7 6.9 0.8
Wholesale:
Price Variance 43.8 (55.6)
Volume Variance (20.2) 89.6
23.6 6.0 34.0 9.5
Other Operating Revenues 5.8 4.4
Total $ 63.4 4.8 $ 45.3 3.5
The increase in operating revenues in 1997 can be attributed to
increased retail and wholesale revenues. The increase in retail
revenues results from the accrual of revenues to be recovered from
ratepayers for the increased cost of replacement power and
increased fossil fuel usage during an outage of both units at the
Company's nuclear plant. Under the retail jurisdictional fuel
clauses, revenues are accrued for the unrecovered cost of fuel in
both retail jurisdictions and for replacement power costs in the
Michigan jurisdiction until approved for billing. The increase in
wholesale revenues in 1997 was mainly due to the introduction of
new power marketing transactions in July 1997. The new power
marketing transactions involve the purchase and sale of electricity
outside the AEP transmission system. The increase in power
marketing sales was offset by a decrease in sales to the Power Pool
due mainly to the outage of Cook Plant. The reduction in sales to
the Power Pool did not lead to a corresponding decrease in revenues
since capacity credits continue to be received. Capacity credits
are designed to allocate the cost of the AEP System's generating
capacity among the members of the Power Pool based on the Power
Pool members relative peak demands and generating reserves. The
Company is compensated for the out-of-pocket costs of energy
delivered to the Power Pool.
Operating revenues increased in 1996 primarily as a result of
increased wholesale sales attributable to increased internal
generation being supplied to the Power Pool and unaffiliated
utilities. The Company's share of Power Pool allocated sales
increased 40% due to increased transactions with other utilities
and power marketers. During 1996 the Company provided coal
conversion services to power marketers and unaffiliated utilities
resulting in 1.2 billion kilowatthours of electricity being
generated under a new FERC-approved interruptible tariff for the
conversion of customers' coal to electricity and does not include
any fuel cost. 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 kilowatthour was
significantly less in 1996 than in 1995.
Operating Expenses Increase
Total operating expenses increased 7% in 1997 primarily due to
an increase in power purchases. The 3% increase in 1996 was mainly
due to the increased operation of the Company's nuclear units,
increased Power Pool wholesale transactions, and higher income
taxes partially offset by a significant reduction in maintenance
expense. The changes in operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions) 1997 1996
Amount % Amount %
Fuel $(9.8) (4.2) $ 13.3 6.0
Purchased Power 78.8 56.8 13.3 10.6
Other Operation 23.6 7.6 3.5 1.2
Maintenance 2.5 2.2 (26.5) (18.7)
Depreciation and
Amortization 0.4 0.3 1.6 1.2
Amortization of Rockport
Plant Unit 1 Phase-in
Plan Deferrals (3.8) (24.1) - -
Taxes Other Than
Federal Income Taxes (8.8) (11.9) 1.9 2.7
Federal Income Taxes (6.8) (8.8) 23.5 43.5
Total $76.1 6.9 $ 30.6 2.8
The decrease in fuel expense in 1997 reflects a 36% decrease in
nuclear generation as both nuclear units were unavailable from
September 9 through the end of the year. See Cook Plant shutdown
discussed above. The decrease in nuclear generation was partially
offset by a 6% increase in fossil generation. Fuel expense
increased in 1996 due to a 17% increase in nuclear generation made
possible by the shorter refueling outage in 1996 versus an extended
refueling and maintenance outage in 1995. This increase was
partially offset by a lower average price per ton of coal consumed
from a favorable settlement of a coal transportation dispute.
Purchased power expense increased significantly in 1997 due to
the Company's share of purchases of power by AEP's new power
marketing business and increased purchases from the Power Pool to
replace power usually generated by the out-of-service nuclear
units. The rise in purchased power expense in 1996 was mainly due
to additional power purchases under an agreement with the Ohio
Valley Electric Corporation, an affiliated company which is not a
member of the Power Pool, and increased purchases from the Power
Pool to support the Company's allocated share of higher Power Pool
wholesale transactions with non-affiliated utilities.
Other operation expense increased in 1997 due to the effect of
gains on the disposition of emission allowances recorded in 1996
and higher administrative and general costs and uncollectible
accounts receivable expenses.
The substantial decrease in maintenance expense in 1996 was due
to cost-reduction measures at the Company's nuclear plant, which
reduced the number of employees performing maintenance and lowered
payments for contract maintenance labor.
The recovery period for Rockport Plant Unit 1 costs deferred
under a rate phase-in plan in the Indiana jurisdiction ended in
August 1997 causing the decrease in the amortization of phase-in
plan deferrals. The deferred costs were amortized over a 10-year
period commensurate with their collection from customers pursuant
to an order of the Indiana Utility Regulatory Commission (IURC).
The decrease in taxes other than federal income taxes in 1997
was due to decreases in real and personal property taxes, Michigan
single business tax and Indiana supplemental income tax.
Federal income taxes attributable to operations decreased in
1997 due to a decrease in pre-tax operating income. The increase
in 1996 reflects an increase in pre-tax operating income and
changes in certain book/tax differences accounted for on a flow-through
basis for rate-making purposes.
Financing Costs
The decline in interest charges in 1996 was due to debt
repayments and a refinancing program which lowered interest rates.
Financial Condition
In 1997 the Company maintained its strong financial condition.
We redeemed 790,967 shares of cumulative preferred stock with rates
ranging from 4.12% to 6.875% at a total cost of $79 million. 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 $48 million principal amount of long-term
obligations in 1997 at 6.4%. We continued to reduce financing
costs by retiring higher-cost bonds and restructuring the long-term
debt from senior secured/first mortgage bonds to senior unsecured
debt and junior debentures. The principal amount of long-term debt
retirements, including maturities, totaled $50 million at 8.75%.
Our senior secured debt/first mortgage bond ratings which were
reaffirmed and improved in 1997, are: Moody's, Baa1; Standard &
Poor's, A-; and Fitch, BBB+.
Gross plant and property additions were $235 million in 1997
and $144 million in 1996. Management estimates construction
expenditures for the next three years to be $456 million which
includes the replacement of the Cook Plant Unit 1 steam generators.
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. (AEP Co., Inc.)
However, all of the construction expenditures for the next three
years are expected to be financed with internally generated funds.
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
$175 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 7.57 and
2.88, respectively.
The Company is committed under unit power agreements to
purchase 70% of an affiliated (AEGCo's) share of the 1,300 mw
Rockport Plant capacity unless it is sold to other utilities.
AEGCo has a long contract with an unaffiliated utility for 455 mw
that expires in 1999. AEGCo's total revenues from this contract in
1997 were $72 million including capacity and energy charges.
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 COLI interest deductions be proposed it would, if
sustained, reduce earnings by approximately $59 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 results of operations, cash flows or financial
condition.
New Accounting Standards
In June 1997 the FASB issued SFAS 130 "Reporting Comprehensive
Income" and SFAS 131 "Disclosures About Segments of an Enterprise
and Related Information." SFAS 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 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. I&M's
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 Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets of
Indiana Michigan 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 Indiana
Michigan 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
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
1997 1996 1995
(in thousands)
OPERATING REVENUES $1,391,917 $1,328,493 $1,283,157
OPERATING EXPENSES:
Fuel 226,402 236,237 222,967
Purchased Power 217,460 138,687 125,413
Other Operation 334,115 310,513 306,967
Maintenance 117,780 115,300 141,813
Depreciation and Amortization 140,812 140,437 138,814
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 11,871 15,644 15,644
Taxes Other Than Federal Income Taxes 64,945 73,729 71,791
Federal Income Taxes 70,744 77,529 54,025
Total Operating Expenses 1,184,129 1,108,076 1,077,434
OPERATING INCOME 207,788 220,417 205,723
NONOPERATING INCOME 4,415 2,729 6,272
INCOME BEFORE INTEREST CHARGES 212,203 223,146 211,995
INTEREST CHARGES 65,463 65,993 70,903
NET INCOME 146,740 157,153 141,092
PREFERRED STOCK DIVIDEND REQUIREMENTS 5,736 10,681 11,791
EARNINGS APPLICABLE TO COMMON STOCK $ 141,004 $ 146,472 $ 129,301
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1997 1996 1995
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 146,740 $ 157,153 $ 141,092
Adjustments for Noncash Items:
Depreciation and Amortization 148,630 148,123 148,441
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 11,871 15,644 15,644
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) (15,967) 7,662 8,684
Deferred Federal Income Taxes 3,922 (24,687) (23,564)
Deferred Investment Tax Credits (8,428) (8,729) (9,004)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,456) (10,235) 4,121
Fuel, Materials and Supplies 5,168 903 (6,255)
Accrued Utility Revenues 7,774 5,642 (3,355)
Accounts Payable 6,502 1,186 (2,431)
Taxes Accrued (18,550) (6,296) 8,075
Other (net) (16,995) 7,975 (23,099)
Net Cash Flows From Operating Activities 260,211 294,341 258,349
INVESTING ACTIVITIES:
Construction Expenditures (122,360) (95,046) (117,785)
Long-term Receivable from Customer
for Construction of Facilities - 62 (18,733)
Proceeds from Sales of Property and Other 2,016 2,714 9,325
Net Cash Flows Used For Investing Activities (120,344) (92,270) (127,193)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 47,728 38,579 96,819
Retirement of Cumulative Preferred Stock (78,877) (30,568) -
Retirement of Long-term Debt (50,000) (46,091) (141,122)
Change in Short-term Debt (net) 76,100 (46,475) 39,375
Dividends Paid on Common Stock (131,260) (112,508) (110,852)
Dividends Paid on Cumulative Preferred Stock (5,931) (10,498) (11,560)
Net Cash Flows Used For Financing Activities (142,240) (207,561) (127,340)
Net Increase (Decrease) in Cash and Cash Equivalents (2,373) (5,490) 3,816
Cash and Cash Equivalents January 1 8,233 13,723 9,907
Cash and Cash Equivalents December 31 $ 5,860 $ 8,233 $ 13,723
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1997 1996
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,545,484 $2,525,969
Transmission 908,736 881,407
Distribution 737,902 696,069
General (including nuclear fuel) 233,888 189,619
Construction Work in Progress 88,487 84,605
Total Electric Utility Plant 4,514,497 4,377,669
Accumulated Depreciation and Amortization 1,973,937 1,861,893
NET ELECTRIC UTILITY PLANT 2,540,560 2,515,776
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 566,390 490,778
OTHER PROPERTY AND INVESTMENTS 156,228 154,265
CURRENT ASSETS:
Cash and Cash Equivalents 5,860 8,233
Accounts Receivable:
Customers 107,087 90,656
Affiliated Companies 15,662 13,727
Miscellaneous 14,561 21,439
Allowance for Uncollectible Accounts (1,188) (156)
Fuel - at average cost 17,182 23,977
Materials and Supplies - at average cost 78,701 77,074
Accrued Utility Revenues 30,521 38,295
Prepayments 4,685 10,271
TOTAL CURRENT ASSETS 273,071 283,516
REGULATORY ASSETS 400,489 421,692
DEFERRED CHARGES 31,060 31,457
TOTAL $3,967,798 $3,897,484
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
December 31,
1997 1996
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 732,472 731,272
Retained Earnings 278,814 269,071
Total Common Shareholder's Equity 1,067,870 1,056,927
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 9,435 21,977
Subject to Mandatory Redemption 68,445 135,000
Long-term Debt 1,014,237 1,042,104
TOTAL CAPITALIZATION 2,159,987 2,256,008
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 381,016 313,845
Other 232,667 174,903
TOTAL OTHER NONCURRENT LIABILITIES 613,683 488,748
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 35,000 -
Short-term Debt 119,600 43,500
Accounts Payable - General 36,729 31,015
Accounts Payable - Affiliated Companies 31,665 30,877
Taxes Accrued 46,850 65,400
Interest Accrued 15,741 15,281
Obligations Under Capital Leases 34,033 29,740
Other 63,250 66,436
TOTAL CURRENT LIABILITIES 382,868 282,249
DEFERRED INCOME TAXES 559,708 594,879
DEFERRED INVESTMENT TAX CREDITS 138,045 146,473
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 92,419 96,125
DEFERRED CREDITS 21,088 33,002
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $3,967,798 $3,897,484
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
1997 1996 1995
(in thousands)
Retained Earnings January 1 $269,071 $235,107 $216,658
Net Income 146,740 157,153 141,092
415,811 392,260 357,750
Deductions:
Cash Dividends Declared:
Common Stock 131,260 112,508 110,852
Cumulative Preferred Stock:
4-1/8% Series 249 495 495
4.56% Series 88 273 273
4.12% Series 80 165 165
5.90% Series 985 2,360 2,360
6-1/4% Series 1,266 1,875 1,875
6.30% Series 834 2,205 2,205
6-7/8% Series 1,255 2,063 2,063
7.08% Series - 531 2,124
Total Cash Dividends Declared 136,017 122,475 122,412
Capital Stock Expense 980 714 231
Total Deductions 136,997 123,189 122,643
Retained Earnings December 31 $278,814 $269,071 $235,107
</TABLE
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES:
Organization
Indiana Michigan Power Company (the Company or I&M) 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 to 549,000 retail customers in its
service territory in northern and eastern Indiana and a portion of
southwestern Michigan. 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, its facilities are operated in conjunction with the
facilities of certain other AEP affiliated utilities as an
integrated utility system.
The Company has two wholly-owned subsidiaries, that were
formerly engaged in coal-mining operations which are consolidated
in these financial statements, Blackhawk Coal Company and Price
River Coal Company. Blackhawk Coal Company currently leases and
subleases portions of its Utah coal rights, land and related mining
equipment to unaffiliated companies. Price River Coal Company,
which owns no land or mineral rights, is inactive.
Regulation
As a subsidiary of AEP Co., Inc., I&M is subject to regulation
by the Securities and Exchange Commission (SEC) under the Public
Utility Holding Company Act of 1935 (1935 Act). Retail rates are
regulated by the Indiana Utility Regulatory Commission (IURC) and
the Michigan Public Service Commission (MPSC). The Federal Energy
Regulatory Commission (FERC) regulates wholesale rates.
Principles of Consolidation
The consolidated financial statements include I&M and its
wholly-owned subsidiaries. Significant intercompany items are
eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, I&M'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 cost-based 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 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 and Amortization
Depreciation of electric utility plant is provided on a
straight-line basis over the estimated useful lives of utility
plant and is calculated largely through the use of composite rates
by functional class as follows:
Functional Class Annual Composite
of Property Depreciation Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 4.4%
Hydroelectric-Conventional 3.2%
Transmission 1.9%
Distribution 4.2%
General 3.8%
Amounts for the demolition and removal of non-nuclear plant are
presently recovered through depreciation charges included in rates.
The accounting and rate-making treatment afforded nuclear decommis-
sioning costs and nuclear fuel disposal costs are discussed in Note
3.
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. Fuel costs are
matched with revenues in accordance with rate commission orders.
Revenues are accrued related to unrecovered fuel in both retail
jurisdictions and for replacement power costs in the Michigan
jurisdiction until approved for billing. If the Company's earnings
exceed the allowed return in the Indiana jurisdiction, the fuel
clause mechanism provides for the refunding of the excess earnings
to ratepayers. Wholesale jurisdictional fuel cost changes are
expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs
Incremental operation and maintenance costs associated with
refueling outages at the Donald C. Cook Nuclear Plant (Cook Plant)
are deferred commensurate with their rate-making treatment and
amortized over the period (generally eighteen months) beginning
with the commencement of an outage and ending with the beginning of
the next outage.
Income Taxes
The Company follows the liability method of accounting for
income taxes as prescribed by SFAS No. 109, "Accounting for Income
Taxes." Under the liability method, deferred income taxes are
provided for all temporary differences between the book cost and
tax basis of assets and liabilities which will result in a future
tax consequence. Where the flow-through method of accounting for
temporary differences is reflected in rates, deferred income taxes
are provided with related regulatory assets and liabilities in
accordance with SFAS No. 71.
Investment Tax Credits
Based on directives of regulatory commissions, the Company
reflected investment tax credits in rates and on its books on a
deferral basis. Commensurate with rate treatment deferred
investment tax credits are being amortized over the life of the
related plant investment. The Company's policy with regard to
investment tax credits for nonutility property is to practice the
flow-through method of accounting.
Debt and Preferred Stock
Gains and losses on reacquistion 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 reduce retained
earnings commensurate with their recovery in rates. The excess of
par value over the cost of preferred stock reacquired is credited
to paid-in capital and amortized to retained earnings.
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
Securities held in trust funds for decommissioning nuclear
facilities and for the disposal of spent nuclear fuel are recorded
at market value in accordance with SFAS No. 115, "Accounting for
Certain Investments in Debt and Equity Securities." Securities in
the trust funds have been classified as available-for-sale due to
their long-term purpose. Due to the rate-making process,
adjustments for unrealized gains and losses are not reported in
equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or
liabilities for the spent nuclear fuel disposal trust funds.
Other Property and Investments
Other property and investments are stated at cost.
2. EFFECTS OF REGULATION AND PHASE-IN PLANS:
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 were to
no longer meet 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 $277,966 $317,059
Department of Energy
Decontamination and
Decommissioning Assessment 42,648 45,994
Rate Phase-in Plan Deferrals - 11,871
Nuclear Refueling
Outage Cost Levelization 31,772 15,805
Unamortized Loss On
Reacquired Debt 17,210 19,388
Other 30,893 11,575
Total Regulatory Assets $400,489 $421,692
Regulatory Liabilities:
Deferred Investment Tax Credits $138,045 $146,473
Other* 1,262 16
Total Regulatory Liabilities $139,307 $146,489
* Included in Deferred Credits on Consolidated Balance
Sheets.
The Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.
I&M and AEP Generating Company (AEGCo), an affiliate,
each own 50% of one unit (Rockport 1) and each lease a 50% interest
in the other unit (Rockport 2) from unaffiliated lessors under an
operating lease. The gain on the sale and leaseback of Rockport 2
was deferred and is being amortized, with related taxes, over the
initial lease term which expires in 2022.
Rate phase-in plans in the Company's Indiana and FERC
jurisdictions provided for the recovery and straight-line
amortization of deferred Rockport Plant Unit 1 costs over ten years
beginning in 1987. In 1997 the amortization and recovery of the
deferred Rockport Plant Unit 1 Phase-in Plan costs was completed.
During the recovery period net income was unaffected by the
recovery of the phase-in deferrals. Amortization was $11.9 million
in 1997 and $15.6 million in 1996 and 1995.
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
the Company's utility operations including the replacement of the
Cook Plant Unit 1 steam generators. Such commitments do not
include any expenditures for new generating capacity. Aggregate
construction program expenditures for 1998-2000 are estimated to be
$456 million.
Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments. The retail jurisdictions have fuel
clause mechanisms that provide for recovery of changes in the cost
of fuel with the regulators' review and approval. The contracts
are for various terms, the longest of which extends to 2014, and
contain various clauses that would release the Company from its
obligation under certain force majeure conditions.
The Company is committed under unit power agreements to
purchase 70% of an affiliate's (AEGCo's) share of the 1,300 mw
Rockport Plant capacity unless it is sold to unaffiliated
utilities. AEGCo has one long-term contract with an unaffiliated
utility that expires in 1999 for 455 mw of Rockport Plant capacity.
The Company sells under contract up to 250 mw of its Rockport
Plant capacity to an unaffiliated utility. The contract expires in
2009.
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 ultimate outcome
of litigation, it is not expected that the resolution of these
matters will have a material adverse effect on the results of
operations, cash flows and financial condition.
Nuclear Plant
I&M owns and operates the two-unit 2,110 mw Donald C. Cook
Nuclear Plant under licenses granted by the Nuclear Regulatory
Commission. The operation of a nuclear facility involves special
risks, potential liabilities, and specific regulatory and safety
requirements. Should a nuclear incident occur at any nuclear power
plant facility in the United States, the resultant liability could
be substantial. By agreement I&M is partially liable together with
all other electric utility companies that own nuclear generating
units for a nuclear power plant incident. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds
and recovery is not possible, results of operations and financial
condition would be negatively affected.
Nuclear Plant Shutdown
On September 9 and 10, 1997, during a Nuclear Regulatory
Commission (NRC) architect engineer design inspection, questions
regarding the operability of certain safety systems caused Company
operations personnel to shut down Units 1 and 2 of the Cook Nuclear
Plant. On September 19, 1997, the NRC issued a Confirmatory Action
Letter requiring the Company to address the issues identified in
the letter. The Company is working with the NRC to resolve these
issues and other issues related to restart of the units. Certain
issues identified in the letter have been addressed. At this time
management is unable to determine when the units will be returned
to service. If the units are not returned to service in a timely
manner, it could have an adverse impact on results of operations,
cash flows and possibly financial condition.
Nuclear Incident Liability
Public liability is limited by law to $8.9 billion should an
incident occur at any licensed reactor in the United States.
Commercially available insurance provides $200 million of coverage.
In the event of a nuclear incident at any nuclear plant in the
United States the remainder of the liability would be provided by
a deferred premium assessment of $79.3 million on each licensed
reactor payable in annual installments of $10 million. As a
result, I&M could be assessed $158.6 million per nuclear incident
payable in annual installments of $20 million. The number of
incidents for which payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide
$3.6 billion (reduced to $3.0 billion effective January 1, 1998) of
property damage, decommissioning and decontamination coverage for
Cook Plant. Additional insurance provides coverage for extra costs
resulting from a prolonged accidental Cook Plant outage. Some of
the policies have deferred premium provisions which could be
triggered by losses in excess of the insurer's resources. The
losses could result from claims at the Cook Plant or certain other
non-affiliated nuclear units. The Company could be assessed up to
$35.8 million annually under these policies.
Spent Nuclear Fuel Disposal
Federal law provides for government responsibility for
permanent spent nuclear fuel disposal and assesses nuclear plant
owners fees for spent fuel disposal. A fee of one mill per
kilowatthour for fuel consumed after April 6, 1983 is being
collected from customers and remitted to the U.S. Treasury. Fees
and related interest of $181 million for fuel consumed prior to
April 7, 1983 have been recorded as long-term debt. I&M has not
paid the government the pre-April 1983 fees due to continued delays
and uncertainties related to the federal disposal program. At
December 31, 1997, funds collected from customers towards the pre-April
1983 fee and related earnings thereon approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposal
Decommissioning costs are accrued over the service life of the
Cook Plant. The licenses to operate the two nuclear units expire
in 2014 and 2017. After expiration of the licenses the plant is
expected to be decommissioned through dismantlement. A 1997
nuclear decommissioning study has been completed. The estimated
cost of decommissioning and low level waste accumulation disposal
costs ranges from $700 million to $1,152 million in 1997
nondiscounted dollars. The wide range is caused by variables in
assumptions including the estimated length of time spent nuclear
fuel must be stored at the plant subsequent to ceasing operations.
This in turn depends on future developments in the federal
government's spent nuclear fuel disposal program. Continued delays
in the federal fuel disposal program can result in increased
decommissioning costs. The Company is recovering estimated
decommissioning costs in its three rate-making jurisdictions based
on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The
Company records decommissioning costs in other operation expense
and records a noncurrent liability equal to the decommissioning
cost recovered in rates; such amount was $28 million in 1997, $27
million in 1996 and $30 million in 1995 including $4 million of
special deposits. Decommissioning costs recovered from customers
are deposited in external trusts. Trust fund earnings increase the
fund assets and the recorded liability thereby decreasing the
amount needed to be recovered from ratepayers. At December 31,
1997 the Company has recognized a decommissioning liability of $381
million.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP 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 AEP System Interconnection
Agreement, capacity charges and credits are designed to allocate
the cost of the AEP 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 include revenues for capacity and energy
supplied to the Power Pool as follows:
Year Ended December 31,
1997 1996 1995
(in thousands)
Capacity Revenues $ 53,282 $ 57,594 $ 59,918
Energy Revenues 64,861 98,162 83,799
Total $118,143 $155,756 $143,717
Purchased power expense includes charges of $51.0 million in
1997, $34.5 million in 1996 and $25.4 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
wholesale power pool sales included in operating revenues were
$127.4 million in 1997, $73.4 million in 1996 and $52.6 million in
1995.
In addition, the Power Pool purchases power from unaffiliated
entities for resale to other unaffiliated entities. The Company's
share of these purchases was included in purchased power expense
and totaled $67.9 million (including new power marketing
transactions) in 1997, $8.1 million in 1996 and $10.7 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.
The cost of Rockport Plant power purchased from AEGCo, an
affiliated company that is not a member of the Power Pool, was
included in purchased power expense in the amounts of $87.5
million, $85.4 million and $85.2 million in 1997, 1996 and 1995,
respectively.
The cost of power purchased from Ohio Valley Electric
Corporation, an affiliated but non-associated company that is not
a member of the Power Pool, was included in purchased power
expense in the amounts of $11.0 million, $10.7 million and $4.0
million in 1997, 1996 and 1995, respectively.
The Company operates the Rockport Plant and bills AEGCo for its
share of operating costs.
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 AEP 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 credits of $46.1 million, $46.3 million and $46.7
million in 1997, 1996 and 1995, respectively.
Revenues from providing barging services were recorded in
nonoperating income as follows:
Year Ended December 31,
1997 1996 1995
(in thousands)
Affiliated Companies $24,427 $22,740 $23,160
Unaffiliated Companies 8,383 6,776 6,992
Total $32,810 $29,516 $30,152
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.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System
pension plan, a trusteed, noncontributory defined benefit plan
covering all employees meeting eligibility requirements. Benefits
are based on service years and compensation levels. 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 required
contribution in accordance with the Employee Retirement Income
Security Act of 1974. Net pension costs for the years ended
December 31, 1997, 1996 and 1995 were $2.1 million, $4.1 million
and $2.7 million, respectively.
Postretirement benefits other than pensions (OPEB) are provided
for retired employees under an AEP System plan. Substantially all
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. 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 106, "Employers Accounting for Postretirement Benefits
Other Than Pensions," exceeds the pay-as-you-go amount).
Contributions were $6.3 million in 1997, $8.4 million in 1996 and
$10.3 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
$11.5 million, $12.8 million and $13.6 million, respectively.
An employee savings plan is offered 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, $3.7
million in 1996 and $3.9 million in 1995.
6. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1997 1996 1995
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $ 62,274 $ 64,117 $71,457
Income Taxes 120,212 125,707 88,675
Noncash Acquisitions
Under Capital Leases 111,395 48,305 32,073
In connection with the 1996 early termination of a western coal
land sublease the Company will receive cash payments from the
lessee of $30.8 million over a ten-year period which has been
recorded at a net present value of $22.8 million. In connection
with the 1995 sale of western coal land and equipment the Company
will receive cash payments from the buyer of $31.5 million over a
six year period which has been recorded at a net present value of
$26.9 million. In connection with construction of facilities in
1995 to provide service to a new customer the Company will receive
cash payments of $21.4 million plus accrued interest over 20 years.
The long-term portion of these receivables is recorded as other
property and investments and the current portion is recorded as
miscellaneous accounts receivable.
7. 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 $ 75,442 $110,133 $ 75,686
Deferred 3,088 (24,730) (13,732)
Deferred Investment Tax Credits (7,786) (7,874) (7,929)
Total 70,744 77,529 54,025
Charged (Credited) to Nonoperating Income (net):
Current 3,287 182 12,872
Deferred 834 43 (9,832)
Deferred Investment Tax Credits (642) (855) (1,075)
Total 3,479 (630) 1,965
Total Federal Income Taxes as Reported $ 74,223 $ 76,899 $ 55,990
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 $146,740 $157,153 $141,092
Federal Income Taxes 74,223 76,899 55,990
Pre-tax Book Income $220,963 $234,052 $197,082
Federal Income Tax on Pre-tax Book Income at
Statutory Rate (35%) $77,337 $81,918 $68,979
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Depreciation 14,082 13,880 8,954
Corporate Owned Life Insurance (3,348) (2,178) (5,187)
Investment Tax Credits (net) (8,428) (8,729) (9,004)
Other (5,420) (7,992) (7,752)
Total Federal Income Taxes as Reported $74,223 $76,899 $55,990
Effective Federal Income Tax Rate 33.6% 32.9% 28.4%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
December 31,
1997 1996
(in thousands)
Deferred Tax Assets $ 223,772 $ 241,842
Deferred Tax Liabilities (783,480) (836,721)
Net Deferred Tax Liabilities $(559,708) $(594,879)
Property Related
Temporary Differences $(471,898) $(480,818)
Amounts Due From Customers
For Future Federal
Income Taxes (74,282) (79,658)
Deferred State Income Taxes (65,679) (89,471)
Deferred Net Gain -
Rockport Plant Unit 2 32,347 33,644
All Other (net) 19,804 21,424
Total Net Deferred
Tax Liabilities $(559,708) $(594,879)
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 AEP 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 parent company, AEP Co., Inc., is
allocated to its subsidiaries with taxable income. With the
exception of the loss of the System 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 cost of medical
benefits for retired employees. AEP filed a brief with the IRS
National Office refuting the agents' position. Although no
adjustments have been proposed, a disallowance of the COLI interest
deductions through December 31, 1997 would reduce earnings by
approximately $59 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.
8. FAIR VALUE OF FINANCIAL INSTRUMENTS:
Nuclear Trust Funds Recorded at Market Value
The Nuclear Decommissioning and Spent Nuclear Fuel Disposal
Trust Fund investments are recorded at market value in accordance
with SFAS 115 and consist of tax-exempt municipal bonds and other
securities.
At December 31, 1997 and 1996 the fair values of trust fund
investments were $566 million and $491 million, respectively.
Accumulated gross unrealized holding gains were $41 million and
$21.9 million and accumulated gross unrealized holding losses were
$1.2 million at both December 31, 1997 and 1996. The change in
market value in 1997, 1996 and 1995 was a net unrealized holding
gain of $19.1 million, $2.6 million and $24.9 million,
respectively.
The trust fund investments' cost basis by security type were:
December 31,
1997 1996
(in thousands)
Tax-Exempt Bonds $335,358 $340,290
Equity Securities 74,398 54,389
Treasury bonds 44,200 26,958
Corporate Bonds 9,167 7,977
Cash, Cash Equivalents
and Interest Accrued 63,392 40,430
Total $526,515 $470,044
Proceeds from sales and maturities of securities of $147.3
million during 1997 resulted in $3.9 million of realized gains and
$1.4 million of realized losses. Proceeds from sales and
maturities of securities of $115.3 million during 1996 resulted in
$2.6 million of realized gains and $2.1 million of realized losses.
Proceeds from sales and maturities of securities of $78.2 million
during 1995 resulted in $1.4 million of realized gains and $0.3
million of realized losses. The cost of securities for determining
realized gains and losses is original acquisition cost including
amortized premiums and discounts.
At December 31, 1997, the year of maturity of trust fund
investments, other than equity securities, was:
(in thousands)
1998 $ 87,063
1999-2002 127,575
2003-2007 182,873
After 2007 54,606
Total $452,117
Other Financial Instruments Recorded at Historical Cost
The carrying amounts of cash and cash equivalents, accounts
receivable, short-term debt, and accounts payable approximate fair
value because of the short-term maturity of these instruments.
Fair values for preferred stocks subject to mandatory redemption
were $73 million and $137 million at December 31, 1997 and 1996,
respectively, and for long-term debt were $1.1 billion at each year
end. The carrying amounts for preferred stock subject to mandatory
redemption were $68 million and $135 million and for long-term
debt were $1.0 billion at December 31, 1997 and 1996, respectively.
Fair values are based on quoted market prices for the same or
similar issues and the current dividend or interest rates offered
for instruments of the same remaining maturities. The carrying
amount of the spent nuclear fuel disposal trust funds approximates
the Company's estimate of the pre-April 1983 SNF liability.
9. LEASES:
Leases of property, plant and equipment are for periods of up
to 35 years and require payments of related property taxes,
maintenance and operating costs. The Company is leasing 50% of the
1300 MW Rockport 2 generating unit under an operating lease. The
lease has 25 years remaining life and total minimum lease payments
of $1.8 billion. 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 $ 92,067 $ 96,096 $ 96,472
Amortization of Capital Leases 42,882 55,789 45,843
Interest on Capital Leases 9,737 10,624 9,987
Total Rental Costs $144,686 $162,509 $152,302
Properties under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
1997 1996
(in thousands)
Electric Utility Plant:
Production $ 9,218 $ 7,410
Distribution 14,660 14,699
General:
Nuclear Fuel (net of amortization) 103,939 59,681
Other 61,268 60,949
Total Electric Utility Plant 189,085 142,739
Accumulated Amortization 31,358 28,598
Net Electric Utility Plant 157,727 114,141
Other Property 40,746 19,035
Accumulated Amortization 3,246 2,211
Net Other Property 37,500 16,824
Net Properties under Capital Leases $195,227 $130,965
Capital Lease Obligations:*
Noncurrent Liability $161,194 $101,225
Liability Due Within One Year 34,033 29,740
Total Capital Lease Obligations $195,227 $130,965
* Represents the present value of future minimum lease payments.
The noncurrent portion of capital lease obligations is included
in other noncurrent liabilities in the Consolidated Balance Sheets.
Properties under operating leases and related obligations are
not included in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1997:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1998 $ 16,362 $ 96,974
1999 15,005 92,734
2000 13,593 92,472
2001 11,927 91,684
2002 22,520 90,655
Later Years 47,767 1,631,759
Total Future Minimum
Lease Payments 127,174(a) $2,096,278
Less Estimated
Interest Element 35,886
Estimated Present
Value of Future
Minimum Lease
Payments 91,288
Unamortized Nuclear
Fuel 103,939
Total $195,227
(a) Excludes nuclear fuel rentals which are paid in proportion to
heat produced and carrying charges on the unamortized nuclear
fuel balance. There are no minimum lease payment requirements
for leased nuclear fuel.
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1997, authorized shares of cumulative
preferred stock were as follows:
Par Value Shares Authorized
$100 2,250,000
25 11,200,000
The cumulative preferred stock is callable at the price
indicated below plus accrued dividends. The involuntary
liquidation preference is par value. Unissued shares of the
cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance. During 1996 the Company
redeemed and canceled 300,000 shares of the 7.08% series not
subject to mandatory redemption.
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)
4-1/8% $106.125 $100 59,760 233 - 60,007 $6,001 $11,977
4.56% 102 100 44,788 - - 15,212 1,521 6,000
4.12% 102.728 100 20,869 - - 19,131 1,913 4,000
$9,435 $21,977
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) $100 233,000 - - 167,000 $16,700 $ 40,000
6-1/4%(b) 100 97,500 - - 202,500 20,250 30,000
6.30% (b) 100 217,550 - - 132,450 13,245 35,000
6-7/8%(c) 100 117,500 - - 182,500 18,250 30,000
$68,445 $135,000
(a) Not callable until after 2002. There are no aggregate sinking
fund provisions through 2002.
(b) Commencing in 2004 and continuing through 2008 the Company may
redeem, at $100 per share, 20,000 shares of the 5.90% series,
15,000 shares of the 6-1/4% series and 17,500 shares of the 6.30%
series outstanding under sinking fund provisions at its option and
all remaining outstanding shares must be redeemed not later than
2009. Shares redeemed in 1997 may be applied to meet the sinking
fund requirement.
(c) Commencing in 2003 and continuing through the year 2007, a
sinking fund will require the redemption of 15,000 shares each year
and the redemption of the remaining shares outstanding on April 1,
2008, in each case at $100 per share. Shares redeemed in 1997 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 $ 520,317 $ 522,507
Installment Purchase
Contracts 309,269 309,120
Other Long-term Debt (a) 180,837 171,706
Junior Debentures 38,814 38,771
1,049,237 1,042,104
Less Portion Due Within
One Year 35,000 -
Total $1,014,237 $1,042,104
(a) Represents a Nuclear Fuel Disposal liability including
interest accrued payable to the Department of Energy. See Note 3.
First mortgage bonds outstanding were as follows:
December 31,
1997 1996
(in thousands)
% Rate Due
7.00 1998 - May 1 $ 35,000 $ 35,000
7.30 1999 - December 15 35,000 35,000
6.40 2000 - March 1 48,000 -
7.63 2001 - June 1 40,000 40,000
7.60 2002 - November 1 50,000 50,000
7.70 2002 - December 15 40,000 40,000
6.80 2003 - July 1 20,000 20,000
6.55 2003 - October 1 20,000 20,000
6.10 2003 - November 1 30,000 30,000
6.55 2004 - March 1 25,000 25,000
8.75 2022 - May 1 - 50,000
8.50 2022 - December 15 75,000 75,000
7.80 2023 - July 1 20,000 20,000
7.35 2023 - October 1 20,000 20,000
7.20 2024 - February 1 40,000 40,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (net) (2,683) (2,493)
520,317 522,507
Less Portion Due Within One Year 35,000 -
Total $485,317 $522,507
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)
% Rate Due
City of Lawrenceburg, Indiana:
7.00 2015 - April 1 $ 25,000 $ 25,000
5.90 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 50,000 50,000
7.60 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (2,731) (2,880)
Total $309,269 $309,120
(a) A variable interest rate is determined weekly. The average
weighted interest rate was 4.3% for 1997 and 3.5% for 1996.
(b) An adjustable interest rate can be a daily, weekly, commercial
paper or term rate as designated by the Company. A weekly
rate was selected which ranged from 3.0% to 4.6% in 1997 and
from 2.4% to 5.0% in 1996 and averaged 3.8% and 3.4% during
1997 and 1996, respectively.
Under the terms of certain installment purchase contracts, the
Company is required to pay amounts sufficient to enable the cities
to pay 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 generating plants. On the two variable rate series the
principal is payable at the stated maturities or on the demand of
the bondholders at periodic interest adjustment dates which occur
weekly. The variable rate bonds due in 2014 are supported by a
bank letter of credit which expires in 2002. I&M has agreements
that provide for brokers to remarket the adjustable rate bonds due
in 2025 tendered at interest adjustment dates. In the event
certain bonds cannot be remarketed, I&M has a standby bond
purchase agreement with a bank that provides for the bank to
purchase any bonds not remarketed. The purchase agreement expires
in 2000. Accordingly, the variable and adjustable rate installment
purchase contracts have been classified for repayment purposes
based on the expiration dates of the standby purchase agreement and
the letter of credit.
Junior debentures are composed of the following:
December 31,
1997 1996
(in thousands)
% Rate Due
8.00 2026 - March 31 $40,000 $40,000
Unamortized Discount (1,186) (1,229)
Total $38,814 $38,771
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.
At December 31, 1997, future annual long-term debt payments
are as follows:
Amount
(in thousands)
1998 $ 35,000
1999 35,000
2000 98,000
2001 40,000
2002 140,000
Later Years 707,837
Total Principal Amount 1,055,837
Unamortized Discount (6,600)
Total $1,049,237
Short-term debt borrowings are limited by provisions of the
1935 Act to $175 million. Lines of credit are shared with 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 by the banks 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 $ 56,410 6.3%
Commercial Paper 63,190 6.8
Total $119,600 6.6
December 31, 1996:
Notes Payable $ 3,900 5.5%
Commercial Paper 39,600 7.2
Total $43,500 7.0
12. 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, $5.9 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
$1,200,000, $170,000 and $(2,548,000) respectively, represented
gains and expenses associated with cumulative preferred stock
transactions.
13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1997
March 31 $341,313 $59,894 $44,259
June 30 320,508 50,140 33,908
September 30 362,058 60,449 45,091
December 31 368,038 37,305 23,482
1996
March 31 329,883 53,018 35,767
June 30 323,494 50,430 33,507
September 30 339,847 61,123 44,546
December 31 335,269 55,846 43,333