INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
1999 1998 1997 1996 1995
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,394,119 $1,405,794 $1,339,232 $1,328,493 $1,283,157
Operating Expenses 1,285,467 1,239,787 1,131,444 1,108,076 1,077,434
Operating Income 108,652 166,007 207,788 220,417 205,723
Nonoperating Income (Loss) 4,530 (839) 4,415 2,729 6,272
Income Before Interest
Charges 113,182 165,168 212,203 223,146 211,995
Interest Charges 80,406 68,540 65,463 65,993 70,903
Net Income 32,776 96,628 146,740 157,153 141,092
Preferred Stock Dividend
Requirements 4,885 4,824 5,736 10,681 11,791
Earnings Applicable to
Common Stock $ 27,891 $ 91,804 $ 141,004 $ 146,472 $ 129,301
December 31,
1999 1998 1997 1996 1995
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,770,027 $4,631,848 $4,514,497 $4,377,669 $4,319,564
Accumulated Depreciation
and Amortization 2,194,397 2,081,355 1,973,937 1,861,893 1,751,965
Net Electric Utility Plant $2,575,630 $2,550,493 $2,540,560 $2,515,776 $2,567,599
Total Assets $4,576,696 $4,148,523 $3,967,798 $3,897,484 $3,928,337
Common Stock and Paid-in
Capital $ 789,323 $ 789,189 $ 789,056 $ 787,856 $ 787,686
Retained Earnings 166,389 253,154 278,814 269,071 235,107
Total Common Shareholder's
Equity $ 955,712 $1,042,343 $1,067,870 $1,056,927 $1,022,793
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 9,248 $ 9,273 $ 9,435 $ 21,977 $ 52,000
Subject to Mandatory
Redemption (a) 64,945 68,445 68,445 135,000 135,000
Total Cumulative
Preferred Stock $ 74,193 $ 77,718 $ 77,880 $ 156,977 $ 187,000
Long-term Debt (a) $1,324,326 $1,175,789 $1,049,237 $1,042,104 $1,040,101
Obligations Under Capital
Leases (a) $ 187,965 $ 186,427 $ 195,227 $ 130,965 $ 142,506
Total Capitalization
and Liabilities $4,576,696 $4,148,523 $3,967,798 $3,897,484 $3,928,337
(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 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 from forward looking
statements are: electric load and customer growth; abnormal weather
conditions; available sources and costs of fuels; availability of
generating capacity; the speed and degree to which competition is
introduced to the power generation business, the structure and
timing of a competitive market and its impact on energy prices or
fixed rates; the ability to recover regulatory assets and other
stranded costs in connection with deregulation of generation; new
legislation and government regulations; the ability of the Company
to successfully control its costs; the economic climate and growth
in our service territory; unforeseen events affecting the Company's
efforts to restart its nuclear generating units which are on an
extended safety related shutdown; the outcome of litigation with
the Internal Revenue Service (IRS) related to certain interest
deductions for a corporate owned life insurance (COLI) program; the
ability of the Company to successfully challenge new environmental
regulations and to successfully litigate claims that the Company
violated the Clean Air Act; inflationary trends; changes in
electricity market prices; interest rates; and other risks and
unforeseen events.
Indiana Michigan Power Company (the Company) is a wholly-owned
subsidiary of American Electric Power Company, Inc. (AEP Co.,
Inc.), a public utility holding company. The Company is engaged in
the generation, purchase, sale, transmission and distribution of
electric power to 559,000 retail customers in its service territory
in northern and eastern Indiana and a portion of southwestern
Michigan and conducts business as American Electric Power (AEP).
The Company as a member of the AEP System Power Pool (AEP Power
Pool) shares the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers.
The Company also sells wholesale power to municipalities and
electric cooperatives.
The cost of the AEP System's generating capacity is allocated
among the AEP Power Pool members based on their relative peak
demands and generating reserves through the payment or receipt of
capacity charges and credits. AEP Power Pool members are also
compensated for the out-of-pocket costs of energy delivered to the
AEP Power Pool and charged for energy received from the AEP Power
Pool.
The AEP Power Pool calculates each Company's prior twelve month
peak demand relative to the total peak demand of all member
companies as a basis for sharing revenues and costs. The result of
this calculation is each Company's member load ratio (MLR) which
determines each Company's percentage share of revenues or costs.
Since the Company's MLR decreased in 1999 and increased during
1998, the AEP Power Pool allocated to the Company a smaller share
in 1999 and a larger share in 1998 of wholesale revenues and
expenses.
Results of Operations
Net income declined $64 million or 66% in 1999 primarily due to
the cost of efforts to restart the Company's two unit Donald C.
Cook Nuclear Plant (Cook Plant) which was shutdown in September
1997 to address safety concerns and issues.
Although operating revenues increased $67 million or 5% in
1998, net income decreased $50 million or 34% due mainly to
increased purchased power and maintenance expense related to the
extended outage of the Cook Plant and the adverse effect on
non-operating income of losses on certain non-regulated energy trades
outside of the AEP Power Pool's traditional marketing area.
Operating Revenues
Operating revenues decreased 1% in 1999 and increased 5% in
1998. The decrease in 1999 was primarily due to a decline in
margins on wholesale sales and net power trading transactions
within the AEP Power Pool's traditional marketing area. An
increase in retail revenues in 1998 was the primary reason for the
1998 increase. The following analyzes the changes in operating
revenues:
Increase (Decrease)
From Previous Year
(dollars in millions) 1999 1998
Amount % Amount %
Retail:
Residential $ 3.4 $ 26.4
Commercial 0.7 26.1
Industrial (5.7) 38.1
Other (0.2) 0.4
(1.8) (0.2) 91.0 9.6
Wholesale (18.2) (5.7) (40.6) (11.2)
Transmission (0.3) (1.1) 13.4 83.2
Miscellaneous 8.6 68.4 2.8 27.6
Total $(11.7) (0.8) $ 66.6 5.0
Operating revenues decreased in 1999 primarily due to reduced
margins on the Company's MLR share of wholesale sales and net
revenues from regulated power trading transactions in the AEP Power
Pool's traditional marketing area. The decline in margins reflects
the moderation in 1999 of extreme weather in 1998 and capacity
shortages experienced in the summer of 1998.
Revenues from retail customers increased significantly in 1998
due to the accrual of revenues under fuel adjustment clauses for
the increased cost of replacement power and increased fossil fuel
usage necessitated by the extended outage of the Company's two
nuclear units and a 3% increase in sales. 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. See "Nuclear Plant Restart Effort" for discussion of
settlement agreements in the Indiana and Michigan jurisdictions
regarding recovery of deferred Cook Plant fuel-related revenues.
Wholesale revenues declined significantly in 1998 due to a
decline in sales to the AEP Power Pool reflecting the
unavailability of the nuclear units. The decline was partially
offset by the Company's MLR share of increased power marketing
sales and net trading transactions of the AEP Power Pool.
Operating Expenses Increase
Total operating expenses increased 4% in 1999 and 10% in 1998
primarily due to costs related to the extended Cook Plant outage
and efforts to restart the units. The changes in the components of
operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions) 1999 1998
Amount % Amount %
Fuel $ 12.8 7.4 $(53.8) (23.8)
Purchased Power (21.1) (7.1) 133.3 80.9
Other Operation 114.3 32.9 13.1 3.9
Maintenance (22.3)(14.1) 39.8 33.8
Depreciation and
Amortization 4.9 3.4 4.3 3.1
Amortization of Rockport
Plant Unit 1 Phase-in
Plan Deferrals - - (11.9)(100.0)
Taxes Other Than
Federal Income Taxes (8.8)(13.1) 2.6 4.1
Federal Income Taxes (34.1)(66.0) (19.1) (27.0)
Total $ 45.7 3.7 $108.3 9.6
Fuel expense increased in 1999 primarily due to an increase in
coal-fired generation as more internal generation was utilized in
place of purchasing power from the AEP Power Pool. The decrease in
fuel expense in 1998 was principally due to the unavailability of
the Company's two nuclear generating units from September 1997
through the end of 1999. See Nuclear Plant Restart Effort
discussed below.
The decrease in purchased power expense in 1999 reflects the
purchase of less power in 1999 at lower prices from the AEP Power
Pool, AEP Generating Company, an affiliate that is not a member of
the AEP Power Pool and unaffiliated entities. Purchased power
expense increased significantly in 1998 due to increased purchases
from the AEP Power Pool and the Company's MLR share of increased
purchases of electricity by the AEP Power Pool. The purchases were
made to replace power previously generated by the unavailable
nuclear units and to supply the electricity for the AEP Power
Pool's wholesale marketing sales.
The increases in other operation expense in 1999 and 1998 were
due to expenditures to prepare the nuclear units for restart.
Maintenance expense declined in 1999 due to cost containment
efforts including staff reductions at the Company's fossil-fired
power plants, in the engineering and maintenance staff of AEP
Service Corporation and in the Company's transmission and
distribution operations. The increase in maintenance expense in
1998 was due to expenditures to prepare the Cook Plant for restart.
The recovery period for the Rockport Plant Unit 1 cost deferral
under rate phase-in plans in the Indiana and the Federal Energy
Regulatory Commission (FERC) jurisdictions ended in 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.
The decrease in taxes other than federal income taxes in 1999
is primarily due to a decline in estimated taxable income for
Indiana supplemental income tax.
Federal income taxes attributable to operations decreased in
1999 and 1998 due to decreases in pre-tax operating income.
Nonoperating Income
The increase in nonoperating income in 1999 is primarily due to
the effect of non-regulated electricity trading transactions, which
resulted in a gain in 1999 and a loss in 1998. The decline in
nonoperating income in 1998 is due to net losses from non-regulated
electricity trading transactions outside of the AEP Power Pool's
traditional marketing area which are marked-to-market.
Interest Charges
Interest charges increased in 1999 due to increased borrowings
to support expenditures, both current and deferred, for the Cook
Plant restart effort.
Business Outlook
The most significant factors affecting the Company's future
earnings are the restart of the Cook Plant nuclear generating
units; weather in the service territories served by the Company and
its wholesale customers; generating unit availability; the ability
to recover costs as the electric generating business becomes more
competitive; the outcome of litigation with the IRS related to
certain interest deductions for a COLI program; and the outcome of
ongoing environmental litigation and proposed air quality
standards. In 1999 significant progress was made related to many
of these major challenges.
Nuclear Plant Restart Effort
Management shut down both units of the Cook Plant in September
1997 due to questions regarding the operability of certain safety
systems that arose during a Nuclear Regulatory Commission (NRC)
architect engineer design inspection. The NRC issued a
Confirmatory Action Letter in September 1997 requiring the Company
to address certain issues identified in the letter. In 1998 the
NRC notified the Company that it had convened a Restart Panel for
Cook Plant and provided a list of required restart activities. In
order to identify and resolve all issues necessary to restart the
Cook units, the Company is working with the NRC and will be meeting
with the Panel on a regular basis until the units are returned to
service. In a February 2, 2000 letter from the NRC, the Company
was notified that the Confirmatory Action Letter had been closed.
Closing of the Confirmatory Action Letter is one of the key
approvals needed to restart the nuclear units.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to restart in April 2000 and Unit 1 scheduled to restart
in September 2000. The restart plan was developed based upon a
comprehensive systems readiness review of all operating systems at
the Cook Plant. When maintenance and other work including testing
required for restart are complete, the Company will seek
concurrence from the NRC to restart the Cook Plant units. Any
issues or difficulties encountered in testing of equipment as part
of the restart process could delay the scheduled restart dates.
Earnings for 2000 will be adversely affected by restart expenses
expected to be incurred in 2000, which are estimated to be $200
million, and amortization of previously deferred non-fuel restart
costs and fuel-related revenues of $78 million.
Replacement of the steam generator for Unit 1 will be completed
before it is returned to service. Costs associated with the steam
generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At December 31, 1999, $119 million has
been spent on the steam generator replacement.
The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal-based purchased power is being
substituted for the unavailable low cost nuclear generation. With
regulator approvals, actual replacement energy fuel costs that
exceeded the costs reflected in billings were recorded as a
regulatory asset under the Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms.
On March 30, 1999, the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolved all matters
related to the recovery of replacement energy fuel costs and all
outage/restart costs and related issues during the extended outage
of the Cook Plant. The settlement agreement provided for, among
other things, a replacement fuel billing credit of $55 million,
including interest, to Indiana retail customers' bills; the
deferral of unrecovered fuel revenues accrued between September 9,
1997 and December 31, 1999, including the billing credit; the
deferral of up to $150 million of jurisdictional restart related
nuclear operation and maintenance costs in 1999 above the amount
included in base rates; the amortization of the deferred fuel and
non-fuel operation and maintenance cost deferrals over a five-year
period ending December 31, 2003; a freeze in base rates through
December 31, 2003; and a fixed fuel recovery charge until March 1,
2004. The $55 million credit was applied to retail customers'
bills during the months of July, August and September 1999.
On December 16, 1999, the Michigan Public Service Commission
(MPSC) approved a settlement agreement for two open Michigan power
supply cost recovery reconciliation cases which resolves all issues
related to the Cook Plant extended outage. The settlement
agreement limits the Company's ability to increase base rates and
freezes the power supply cost recovery factor through December 31,
2003; permits the deferral of up to $50 million in 1999 of
jurisdictional non-fuel restart nuclear operation and maintenance
expenses and authorizes the amortization of power supply cost
recovery revenues accrued from September 9, 1997 to December 31,
1999 and non-fuel nuclear operation and maintenance costs deferrals
over a five-year period ending December 31, 2003.
Expenditures to restart the Cook units are estimated to total
approximately $574 million. Through December 31, 1999, $373
million has been spent. These expenditures are not capital in
nature and as such have negatively affected current earnings and
will negatively affect earnings in 2000, and through amortization
of the above described deferrals through December 31, 2003. In
1999 the restart costs incurred were $289 million of which $200
million were deferred for amortization over a five-year period,
beginning January 1, 1999, in accordance with the settlement
agreements. Consequently, $129 million of restart costs negatively
affected 1999 earnings inclusive of $40 million of amortization of
deferred restart costs. Also reflected in 1999 earnings is
amortization of $38 million of fuel-related revenues. At December
31, 1999, regulatory assets included $160 million of deferred
restart related operation and maintenance costs. Also deferred as
a regulatory asset at December 31, 1999 was $150 million of
fuel-related revenues.
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and
possibly financial condition through 2003 and on cash flows through
2000. Management believes that the Cook units will be successfully
restarted in April and September 2000, however, if for some unknown
reason the units are not returned to service or their restart is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
Restructuring Activities
The introduction of competition and customer choice for retail
customers in the Company's service territory has been slow and
continues at a deliberate pace as legislators and regulatory
officials recognize the complexity of the issues. 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 MPSC 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 MPSC and other interested parties to
formulate a plan. The actions by the MPSC were not mandated by
legislation and are subject to a number of uncertainties and it is
not presently possible to determine what impact if any the
resolution of these matters will have on the operations of the
Company. 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 the best competitive
market structure and method to transition to a competitive
marketplace.
As the pricing of generation in the electric energy market
evolves from regulated cost-of-service ratemaking to market-based
rates, many complex issues must be resolved, including the recovery
of stranded costs. Stranded costs are those costs above market
that potentially would not be recoverable in a competitive market.
At the wholesale level recovery of stranded costs under certain
conditions was addressed by the FERC when it established rules for
open transmission access and competition in the wholesale markets.
However, the issue of stranded cost is unresolved at the retail
level where it is much larger than it is at the wholesale level.
The amount of stranded cost the Company could experience depends on
the timing and extent to which competition is introduced to its
generation business and the future market prices of electricity.
The recovery of stranded cost is dependent on the terms of future
legislation and related regulatory proceedings.
Under the provisions of Statement of Financial Accounting
Standards (SFAS) 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. In order to
maintain net regulatory assets on the balance sheet, SFAS 71
requires that rates charged to customers be cost-based and provide
for the probable recovery of regulatory assets over future
accounting periods. Management has concluded that as of December
31, 1999 the requirements to apply SFAS 71 continue to be met.
In the event a portion of the Company's business no longer
meets the requirements of SFAS 71, SFAS 101 "Accounting for the
Discontinuance of Application of Statement 71" requires that net
regulatory assets be written off for that portion of the business.
The provisions of SFAS 71 and SFAS 101 did not anticipate or
provide accounting guidance for an extended transition period and
for recovery of stranded costs during and after a transition period
through a wires charge or regulated distribution rates. In 1997
the Financial Accounting Standards Board's (FASB) Emerging Issues
Task Force (EITF) addressed such a situation with the consensus
reached on issue 97-4 that requires that the application of SFAS 71
to a segment of a regulated electric utility cease when that
segment is subject to a legislatively approved plan for transition
to competitive market pricing from cost-based regulated rates
and/or a rate order is issued containing sufficient detail for the
utility to reasonably determine what the restructuring plan would
entail and how it will affect the utility's financial statements.
The EITF indicated that the cessation of application of SFAS 71
would require that regulatory assets and impaired stranded plant
cost applicable to the portion of the business that was no longer
cost-based regulated be written off unless they are recoverable in
the future through cost-based regulated rates.
Although certain FERC orders 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. We believe that enabling federal and state
legislation should provide for the recovery of any generation-related
net regulatory assets and other reasonable stranded costs
from impaired generating assets. 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 would be
adversely affected.
The Company supports the orderly transition to market pricing
for electricity because we believe our low cost generating units
provide us with a competitive advantage provided the legislators
and/or regulators provide a level playing field for all
competitors. The Company is working to develop and acquire the
necessary skills and competencies to succeed in a competitive
electricity commodity market. The AEP Power Pool has developed an
extensive wholesale electricity trading business. However, many
factors, some of which the Company does not control, could
negatively impact future success in a market price based,
competitive environment.
Customer choice and competition could ultimately result in
adverse impacts on results of operations and cash flows depending
on the future market prices of electricity and the ability of the
Company to recover its stranded costs including net regulatory
assets during a transition period and during a subsequent period
through a wires charge or other recovery mechanism. We believe
that enabling state legislation and the regulatory process should
provide for the full recovery of generation related net regulatory
assets and other reasonable stranded costs. However, if in the
future any portion of the generation business in our jurisdictions
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 would be adversely affected.
Environmental Concerns and Issues
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 cost effective clean air and water
technologies and to research new technologies. We intend to
continue in a leadership role fostering economically prudent
efforts to protect and preserve the environment while providing a
vital commodity, electricity, to our customers at a fair price.
Air Quality
In 1998 the United States (U.S.) Environmental Protection
Agency (Federal EPA) issued a final rule which requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern states,
including the states in which the Company's generating plants are
located. A number of utilities, including the Company, filed
petitions seeking a review of the final rule in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court). On
March 3, 2000, the Appeals Court issued a decision generally
upholding Federal EPA's final rule on NOx emission reductions.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act. The Rule approved portions of the
states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx emission reduction final rule.
The Company and its affiliates in the AEP System with coal-fired
generating plants, as well as other utility companies, filed a
petition in the Appeals Court seeking review of the Section 126
Rule. In 1999, three additional northeastern states and the
District of Columbia filed petitions with Federal EPA similar to
those originally filed by the eight northeastern states. Since the
petitions relied in part on compliance with an 8-hour ozone
standard remanded by the Appeals Court, Federal EPA indicated its
intent to decouple compliance with the 8-hour standard and issue a
revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126
Rule requiring 392 industrial plants, including certain generating
plants owned by the Company, to reduce their NOx emissions by May
1, 2003. This rule approves petitions of four northeastern states
which contend that their failure to meet Federal EPA smog standards
is due to coal-fired generating plants in upwind states, including
many plants in the AEP System, and not their automobiles and other
local sources.
Preliminary estimates indicate that compliance with the Federal
EPA's final rule on NOx emission reductions that was upheld by the
Appeals Court could result in required capital expenditures of
approximately $202 million for the Company. It should be noted,
however, that compliance costs cannot be estimated with certainty
since actual costs incurred to comply could be significantly
different from this preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions. Unless compliance costs are recovered from customers
through regulated rates, such compliance costs will have an adverse
effect on future results of operations, cash flows and possibly
financial condition.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a fossil plant undergoes a major
modification that results in a significant emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999, the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company and its
affiliates in the AEP System made modifications to certain of their
coal-fired generating plants over the course of the past 25 years
that extend their operating lives or increase their generating
capacity in violation of the Clean Air Act. Federal EPA also
issued Notices of Violation alleging violations of certain
provisions of the Clean Air Act at certain AEP System plants. A
number of unaffiliated utilities also received Notices of
Violation, complaints or administrative orders.
The states of New Jersey, New York and Connecticut were
subsequently allowed to join Federal EPA's action against the AEP
System companies under the Clean Air Act. On November 18, 1999, a
number of environmental groups filed a lawsuit against power plants
owned by the Company and its AEP System affiliates alleging similar
violations to those in the Federal EPA complaint and Notices of
Violation. This action has been consolidated with the Federal EPA
action. The complaints and Notices of Violation named one of the
Company's two coal-fired generating plants. Management believes its
maintenance, repair and replacement activities were in conformity
with the Clean Air Act provisions and intends to vigorously pursue
its defense of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial. In the event the Company does not prevail,
any capital and operating costs of additional pollution control
equipment that may be required as well as any penalties imposed
would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates.
Financial Condition
The Company issued $250 million principal amount of long-term
obligations in 1999; $150 million with an interest rate of 6-7/8%
and $100 million with a variable interest rate. The principal
amount of long-term debt retirements, including maturities, totaled
$110 million at interest rates ranging from 6.55% to 7.3%. Our
senior secured debt/first mortgage bond ratings are: Moody's, Baa1;
Standard & Poor's, A-; and Fitch, BBB+.
Gross plant and property additions were $178 million in 1999
and $159 million in 1998. Management estimates construction
expenditures for the next three years to be $329 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 AEP Co., Inc.
However, all of the construction expenditures for the next three
years are expected to be financed with internally generated funds.
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, 1999, $1,056 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
$500 million. Generally periodic reductions of outstanding
short-term debt are made through issuances of long-term debt and
additional capital contributions by the parent company.
The Company's earnings coverage presently exceeds all minimum
coverage requirements for the issuance of mortgage bonds. The
minimum coverage ratio is 2.0 for mortgage bonds and at December
31, 1999, the mortgage bond coverage ratio was 4.81.
The Company is committed under unit power agreements to
purchase all of an affiliate's share, 50% of the 2,600 megawatt
(mw) Rockport Plant capacity, unless it is sold to other utilities.
The affiliate had a long-term unit power agreement that expired at
the end of 1999 for the sale of 455 mw to an unaffiliated utility.
Revenues received by the affiliate under this agreement were $64
million in 1999. An agreement between the affiliate which owns
Rockport Plant and another affiliate provides for the sale of 390
mw of capacity to that affiliate through 2004. Effective January
1, 2000, the Company is required to purchase 910 mw of its
affiliate's 50% share of Rockport Plant capacity.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. As a member of the AEP Power Pool, trading of
electricity and related financial derivative instruments by the AEP
Power Pool exposes the Company to market risk. Market risk
represents the risk of loss that may impact the Company due to
adverse changes in electricity commodity market prices and rates.
Policies and procedures have been established to identify, assess
and manage market risk exposures including the use of a risk
measurement model which calculates Value at Risk (VaR). The VaR is
based on the variance-covariance method using historical prices to
estimate volatilities and correlations and assuming a 95%
confidence level and a three-day holding period. Throughout 1999
and 1998, the Company's share of the highest, lowest and average
quarterly VaR in the wholesale trading portfolio was less than $2.7
million and $2 million, respectively. Based on this VaR analysis,
at December 31, 1999 a near term change in commodity prices is not
expected to have a material effect on the Company's results of
operations, cash flows or financial condition.
The Company is exposed to changes in interest rates primarily
due to short-term and long-term borrowings to fund its business
operations. The debt portfolio has both fixed and variable
interest rates with terms from one day to 39 years and an average
duration of five years at December 31, 1999. The Company measures
interest rate market risk exposure utilizing a VaR model. The
interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period. The
volatilities and correlations were based on three years of weekly
prices. The risk of potential loss in fair value attributable to
the Company's exposure to interest rates, primarily related to
long-term debt with fixed interest rates, was $127 million at
December 31, 1999 and $102 million at December 31, 1998. The
Company would not expect to liquidate its entire debt portfolio in
a one year holding period. Therefore, a near term change in
interest rates should not materially affect results of operations
or the consolidated financial position of the Company.
Inflation affects the Company's cost of replacing utility plant
and the cost of operating and maintaining its 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.
Litigation
Corporate Owned Life Insurance
The IRS agents auditing the AEP System's consolidated federal
income tax returns requested a ruling from their National Office
that certain interest deductions claimed by the Company relating to
AEP's COLI program should not be allowed. As a result of a suit
filed by the Company in U.S. District Court (discussed below) the
request for ruling was withdrawn by the IRS agents. Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through December 31, 1999 would reduce earnings
by approximately $66 million (including interest).
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the Consolidated Balance Sheets in other property and
investments pending the resolution of this matter. The Company is
seeking refund through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against
the U.S. in the U.S. District Court for the Southern District of
Ohio in March 1998. In 1999 a U.S. Tax Court judge decided in the
Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's
COLI deductions should be disallowed. Notwithstanding the Tax
Court's decision in Winn-Dixie management has made no provision for
any possible adverse earnings impact from this matter because it
believes, and has been advised by outside counsel, that it has a
meritorious position and will vigorously pursue its lawsuit. In
the event the resolution of this matter is unfavorable, it will
have a material adverse impact on results of operations, cash flows
and possibly financial condition.
The Company is involved in a number of other legal proceedings
and claims. While management is unable to predict the outcome of
such litigation, it is not expected that the ultimate resolution of
these matters will have a material adverse effect on the results of
operations, cash flows or financial condition.
Other Matters
Superfund
By-products from the generation of electricity include
materials such as ash, slag, sludge, low-level radioactive waste
and spent nuclear fuel (SNF). 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 (Superfund) addresses clean-up of hazardous
substances at disposal sites and authorizes Federal EPA to
administer the clean-up programs. As of year-end 1999, the Company
has been named by the Federal EPA as a potentially responsible
party (PRP) for two sites. Historically, 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 cleanup costs are incurred, results of operations, cash
flows and possibly financial condition would be adversely affected
unless the costs can be recovered from customers.
The Clean Air Act Amendments (CAAA) required Federal EPA to
issue rules to implement the law. In 1996 Federal EPA issued final
rules governing NOx emissions that must be met after January 1,
2000 (Phase II of CAAA). The final rules required substantial
reductions in NOx emissions from certain types of boilers including
those in the power plants of the Company and its affiliates in the
AEP System. To comply with Phase II of CAAA, the Company installed
NOx emission control equipment on certain units and switched fuel
at other units. The Company is operating under the Phase II rules
which require reporting at the end of each year. The Company does
not anticipate any material problems complying with the rules.
At the Third Conference of the Parties to the United Nations
Framework Convention on Climate Change held in Kyoto, Japan in
December 1997 more than 160 countries, including the U.S.,
negotiated a treaty requiring legally-binding reductions in
emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. The
treaty, which requires the advice and consent of the U.S. Senate
for ratification, would require the U.S. to reduce greenhouse gas
emissions seven percent below 1990 levels in the years 2008-2012.
Although the U.S. has agreed to the treaty and signed it on
November 12, 1998, President Clinton has indicated that he will not
submit the treaty to the Senate for consideration until it contains
requirements for "meaningful participation by key developing
countries" and the rules, procedures, methodologies and guidelines
of the treaty's emissions trading and joint implementation programs
and compliance enforcement provisions have been negotiated. At the
Fourth Conference of the Parties, held in Buenos Aires, Argentina,
in November 1998, the parties agreed to a work plan to complete
negotiations on outstanding issues with a view toward approving
them at the Sixth Conference of the Parties to be held in November
2000. We will continue to work with the Administration and
Congress to develop responsible public policy on this issue.
If the Kyoto treaty is approved by Congress, the costs to
comply with the emission reductions required by the 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. It is management's
belief, that the Kyoto protocol is unlikely to be ratified or
implemented in the U.S. in its current form.
Costs for Spent Nuclear Fuel and Decommissioning
The Company, as the owner of the Cook Plant, like other nuclear
power plants, has a significant future financial commitment to
safely dispose of SNF and decommission and decontaminate the plant.
The Nuclear Waste Policy Act of 1982 established federal
responsibility for the permanent off-site disposal of SNF and
high-level radioactive waste. By law the Company participates in the
Department of Energy's (DOE) SNF disposal program which is
described in Note 5 of the Notes to Consolidated Financial
Statements. Since 1983 we have collected $272 million from
customers for the disposal of nuclear fuel consumed at the Cook
Plant. $115 million of these funds have been deposited in external
trust funds to provide for the future disposal of SNF and $157
million has been remitted to the DOE. Under the provisions of the
Nuclear Waste Policy Act, collections from customers are to provide
the DOE with money to build a permanent repository for spent fuel.
However, in December 1996, the DOE notified the Company that it
would be unable to begin accepting SNF by the January 1998 deadline
required by law. To date DOE has failed to comply with the
requirements of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward
a permanent repository or otherwise assume responsibility for SNF,
the Company along with a number of unaffiliated utilities and
states filed suit in the Appeals Court requesting, among other
things, that the Appeals Court order DOE to meet its obligations
under the law. The Appeals Court ordered the parties to proceed
with contractual remedies but declined to order DOE to begin
accepting SNF for disposal. DOE estimates its planned site for the
nuclear waste will not be ready until at least 2010. In 1998, the
Company filed a complaint in the U.S. Court of Federal Claims
seeking damages in excess of $150 million due to the DOE's partial
material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits
were filed by other utilities. On April 6, 1999, the Court granted
DOE's motion to dismiss a lawsuit filed by another utility. On May
20, 1999, the other utility appealed this decision to the U.S.
Court of Appeals for the Federal Circuit. The Company's case has
been stayed pending final resolution of the other utility's appeal.
As long as the delay in the availability of a government approved
storage repository for SNF continues, the cost of both temporary
and permanent storage will continue to increase.
The cost to decommission the Cook Plant is affected by both NRC
regulations and the delayed SNF disposal program. Studies
completed in 1997 estimate the cost to decommission the Cook Plant
ranges from $700 million to $1,152 million in 1997 nondiscounted
dollars. This estimate could escalate due to continued uncertainty
in the SNF disposal program and the length of time that SNF may
need to be stored at the plant site. External trust funds have
been established with amounts collected from customers to
decommission the plant. At December 31, 1999, the total
decommissioning trust fund balance was $498 million which includes
earnings on the trust investments. We will work with regulators
and customers to recover the remaining estimated cost of
decommissioning the Cook Plant. However, future results of
operations, cash flows and possibly financial condition would be
adversely affected if the cost of SNF disposal and decommissioning
continues to increase and cannot be recovered.
Year 2000 Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems could have produced erroneous results or failed, unless
these systems had been modified or replaced, because such systems
may have been programmed incorrectly and interpreted the date of
January 1, 2000 as being January 1st of the year 1900 or another
incorrect date. In addition, certain systems may fail to detect
that the year 2000 is a leap year or otherwise incorrectly
interpret a year 2000 date.
The Company has not experienced any material failure of
generation and delivery of electric energy due to Year 2000 because
of the AEP System's preparations. Such preparation included the
modification or replacement of certain computer hardware and
software to minimize Year 2000-related failures and repair. This
included both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), such as process controls for energy production
and delivery. Externally, the problem was addressed with entities
that interact with the Company, including suppliers, customers,
creditors, financial service organizations and other parties
essential to the Company's operations. In the course of the
external evaluation, the Company sought written assurances from
third parties regarding their state of Year 2000 readiness.
Another issue addressed was the impact of electric power grid
problems that may have occurred outside of our transmission system.
Through December 31, 1999, the Company's share of the AEP
System's expenditures on the Year 2000 project was $8 million.
Most Year 2000 costs were for IT contractors and consultants and
for salaries of internal IT professionals and were expensed;
however, in certain cases the Company acquired hardware and new
software that was capitalized.
New Accounting Standards
The FASB issued SFAS 133 "Accounting for Derivative Instruments
and Hedging Activities" in June 1998. SFAS 133 establishes
accounting and reporting standards for derivative instruments. It
requires that all derivatives be recognized as either an asset or
a liability and measured at fair value in the financial statements.
If certain conditions are met, a derivative may be designated as a
hedge of possible changes in fair value of an asset, liability or
firm commitment; variable cash flows of forecasted transactions; or
foreign currency exposure. The accounting/reporting for changes in
a derivative's fair value (gains and losses) depend on the intended
use and resulting designation of the derivative. Management is
currently studying the provisions of SFAS 133 and reviewing the
Company's contracts and transactions to determine the impact on the
Company's results of operations, cash flows and financial condition
when SFAS 133 is adopted on January 1, 2001.
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, 1999 and 1998, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1999. 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, 1999
and 1998, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1999
in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2000
(March 3, 2000 as to Note 6)
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
1999 1998 1997
(in thousands)
OPERATING REVENUES $1,394,119 $1,405,794 $1,339,232
OPERATING EXPENSES:
Fuel 185,419 172,592 226,402
Purchased Power 276,962 298,046 164,775
Other Operation 461,494 347,207 334,115
Maintenance 135,331 157,593 117,780
Depreciation and Amortization 149,988 145,112 140,812
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals - - 11,871
Taxes Other Than Federal Income Taxes 58,713 67,592 64,945
Federal Income Taxes 17,560 51,645 70,744
Total Operating Expenses 1,285,467 1,239,787 1,131,444
OPERATING INCOME 108,652 166,007 207,788
NONOPERATING INCOME (LOSS) 4,530 (839) 4,415
INCOME BEFORE INTEREST CHARGES 113,182 165,168 212,203
INTEREST CHARGES 80,406 68,540 65,463
NET INCOME 32,776 96,628 146,740
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,885 4,824 5,736
EARNINGS APPLICABLE TO COMMON STOCK $ 27,891 $ 91,804 $ 141,004
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1999 1998
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,587,288 $2,565,041
Transmission 928,758 913,495
Distribution 818,697 768,888
General (including nuclear fuel) 244,981 228,013
Construction Work in Progress 190,303 156,411
Total Electric Utility Plant 4,770,027 4,631,848
Accumulated Depreciation and Amortization 2,194,397 2,081,355
NET ELECTRIC UTILITY PLANT 2,575,630 2,550,493
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 707,967 648,307
OTHER PROPERTY AND INVESTMENTS 213,658 197,368
CURRENT ASSETS:
Cash and Cash Equivalents 3,863 5,424
Accounts Receivable:
Customers 91,268 94,502
Affiliated Companies 48,901 26,569
Miscellaneous 18,644 18,743
Allowance for Uncollectible Accounts (1,848) (2,027)
Fuel - at average cost 27,597 20,857
Materials and Supplies - at average cost 84,149 78,009
Accrued Utility Revenues 44,428 37,277
Energy Marketing and Trading Contracts 97,946 14,105
Prepayments 7,631 4,848
TOTAL CURRENT ASSETS 422,579 298,307
REGULATORY ASSETS 624,810 421,475
DEFERRED CHARGES 32,052 32,573
TOTAL $4,576,696 $4,148,523
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
December 31,
1999 1998
(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 732,739 732,605
Retained Earnings 166,389 253,154
Total Common Shareholder's Equity 955,712 1,042,343
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 9,248 9,273
Subject to Mandatory Redemption 64,945 68,445
Long-term Debt 1,126,326 1,140,789
TOTAL CAPITALIZATION 2,156,231 2,260,850
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 501,185 445,934
Other 242,522 240,320
TOTAL OTHER NONCURRENT LIABILITIES 743,707 686,254
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 198,000 35,000
Short-term Debt 224,262 108,700
Accounts Payable - General 78,784 53,187
Accounts Payable - Affiliated Companies 31,118 37,647
Taxes Accrued 48,970 35,161
Interest Accrued 13,955 15,279
Obligations Under Capital Leases 11,072 9,667
Energy Marketing and Trading Contracts 95,564 15,228
Other 91,684 72,065
TOTAL CURRENT LIABILITIES 793,409 381,934
DEFERRED INCOME TAXES 622,157 559,288
DEFERRED INVESTMENT TAX CREDITS 121,627 129,779
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 85,005 88,712
DEFERRED CREDITS 54,560 41,706
COMMITMENTS AND CONTINGENCIES (Notes 5 and 6)
TOTAL $4,576,696 $4,148,523
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
1999 1998 1997
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 32,776 $ 96,628 $ 146,740
Adjustments for Noncash Items:
Depreciation and Amortization 153,921 149,209 148,630
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals - - 11,871
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) 8,480 14,142 (15,967)
Deferred Nuclear Outage Costs (net) (160,000) - -
Deferred Federal Income Taxes 85,727 17,905 3,922
Deferred Investment Tax Credits (8,152) (8,266) (8,428)
Underrecovery of Fuel and Purchased Power (84,696) (46,846) (22,812)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (19,178) 1,462 (10,504)
Fuel, Materials and Supplies (12,880) (2,983) 5,168
Accrued Utility Revenues (7,151) (6,756) 7,774
Accounts Payable 19,068 22,440 6,502
Taxes Accrued 13,809 (11,689) (18,550)
Payment of Disputed Tax and Interest Related to COLI (3,228) (53,628) -
Other (net) 12,831 (8,176) 5,817
Net Cash Flows From Operating Activities 31,327 163,442 260,163
INVESTING ACTIVITIES:
Construction Expenditures (165,331) (147,627) (122,360)
Proceeds from Sales of Property and Other 2,501 4,419 2,016
Net Cash Flows Used For Investing Activities (162,830) (143,208) (120,344)
FINANCING ACTIVITIES:
Issuance of Long-term Debt 247,989 170,675 47,728
Retirement of Cumulative Preferred Stock (3,597) (120) (78,877)
Retirement of Long-term Debt (109,500) (55,000) (50,000)
Change in Short-term Debt (net) 115,562 (10,900) 76,100
Dividends Paid on Common Stock (114,656) (117,464) (131,260)
Dividends Paid on Cumulative Preferred Stock (5,856) (4,734) (5,931)
Net Cash Flows From (Used For) Financing Activities 129,942 (17,543) (142,240)
Net Increase (Decrease) in Cash and Cash Equivalents (1,561) 2,691 (2,421)
Cash and Cash Equivalents January 1 5,424 2,733 5,154
Cash and Cash Equivalents December 31 $ 3,863 $ 5,424 $ 2,733
See Notes to Consolidated Financial Statements.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
1999 1998 1997
(in thousands)
Retained Earnings January 1 $253,154 $278,814 $269,071
Net Income 32,776 96,628 146,740
285,930 375,442 415,811
Deductions:
Cash Dividends Declared:
Common Stock 114,656 117,464 131,260
Cumulative Preferred Stock:
4-1/8% Series 244 247 249
4.56% Series 66 67 88
4.12% Series 78 79 80
5.90% Series 963 985 985
6-1/4% Series 1,250 1,266 1,266
6.30% Series 834 834 834
6-7/8% Series 1,238 1,255 1,255
Total Cash Dividends Declared 119,329 122,197 136,017
Capital Stock Expense 212 91 980
Total Deductions 119,541 122,288 136,997
Retained Earnings December 31 $166,389 $253,154 $278,814
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, purchase, sale, transmission and
distribution of electric power to 559,000 retail customers in its
service territory in northern and eastern Indiana and a portion of
southwestern Michigan and conducts business as American Electric
Power (AEP). Under the terms of the AEP System Power Pool (AEP
Power Pool) and the AEP System Transmission Equalization Agreement,
the Company's generation and transmission facilities are operated
in conjunction with the facilities of certain other affiliated
utilities as an integrated utility system. The Company as a member
of the AEP Power Pool shares in the revenues and costs of the AEP
Power Pool's wholesale sales to utility systems and power
marketers. The Company also sells wholesale power to municipalities
and electric cooperatives.
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. The Company's
River Transportation Division provides barging services to
affiliated and unaffiliated companies.
Regulation
As a subsidiary of AEP Co., Inc., the Company is subject to the
regulation of 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 and
transmission rates.
Principles of Consolidation
The consolidated financial statements include the revenues,
expenses, cash flows, assets, liabilities and equity of 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 rate regulated. In accordance with
Statement of Financial Accounting Standards (SFAS) 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 are 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 1999, 1998 and 1997 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. The annual composite depreciation rates for
1999, 1998 and 1997 are as follows:
Functional Class Annual Composite
of Property Depreciation Rates
1999 1998 1997
Production:
Steam-Nuclear 3.4% 3.4% 3.4%
Steam-Fossil-Fired 4.5% 4.4% 4.4%
Hydroelectric-Conventional 3.4% 3.4% 3.2%
Transmission 1.9% 1.9% 1.9%
Distribution 4.2% 4.2% 4.2%
General 3.8% 3.8% 3.8%
Amounts for the demolition and removal of non-nuclear plant are
charged to the accumulated provision for depreciation and recovered
through depreciation charges included in rates. The accounting and
rate-making treatment afforded nuclear decommissioning costs and
nuclear fuel disposal costs are discussed in Note 5.
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 billed revenues as well as an accrual for
electricity consumed but unbilled at month-end. Fuel costs are
matched with revenues in accordance with rate commission orders.
Through December 31, 1999, revenues were accrued related to
unrecovered fuel in both state 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. As part of
settlement agreements related to fuel cost during an extended
outage at the Donald C. Cook Nuclear Plant (Cook Plant) approved by
the IURC and the MPSC, fuel costs could be deferred through
December 31, 1999. Over or under recovered fuel from January 1,
2000 through February 29, 2004 in the Indiana jurisdiction and
through December 31, 2003 in the Michigan jurisdiction will not be
eligible for deferral due to fixed fuel recovery amounts in the
settlement agreements. Effective March 1, 2004 and January 1,
2004, the fixed fuel recovery amount will expire and the Company
will return to recording over and under recovery of fuel costs for
the Indiana and Michigan jurisdictions, respectively, assuming that
generation is still cost-based rate regulated. Substantially all
FERC wholesale jurisdictional fuel cost changes are expensed and
billed as incurred. See Note 2 "Cook Nuclear Plant Shutdown" for
a complete discussion of the settlement agreements.
Energy Marketing and Trading Transactions
The AEP Power Pool administers and implements power marketing
and trading transactions (trading activities) in which the Company
shares. Trading activities involve the sale of electricity under
physical forward contracts at fixed and variable prices and the
trading of electricity contracts including exchange traded futures
and options, over-the-counter options and swaps. The majority of
these transactions represents physical forward electricity
contracts in the AEP Power Pool's traditional marketing area and
are typically settled by entering into offsetting contracts. The
net revenues from these regulated transactions in AEP's traditional
marketing area are included in operating revenues for rate-making,
accounting and financial and regulatory reporting purposes.
In addition, the AEP Power Pool purchases and sells electricity
options, futures and swaps, and enters into forward purchase and
sale contracts for electricity outside of the AEP Power Pool's
traditional marketing area. The Company's share of these
non-regulated trading activities are included in nonoperating income.
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's (FASB) Emerging Issues Task Force
Consensus (EITF) 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities." The EITF requires
that all energy trading contracts be marked-to-market. The effect
on the Consolidated Statements of Income of marking open trading
contracts to market is deferred as regulatory assets or liabilities
for those open trading transactions within the AEP Power Pool's
marketing area that are included in cost of service on a settlement
basis for rate-making purposes. The Company's share of
non-regulated open trading contracts are accounted for on a
mark-to-market basis in nonoperating income. Unrealized mark-to-market
gains and losses from trading activities are reported as assets and
liabilities, respectively. The adoption of the EITF did not have
a material effect on results of operations, cash flows or financial
condition.
The Company enters into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These
anticipatory debt instruments are entered into in order to manage
the change in interest rates between the time a debt offering is
initiated and the issuance of the debt (usually a period of 60
days). Gains or losses on the anticipatory debt instruments are
deferred and amortized over the life of the debt issuance with the
amortization included in interest charges. There were no such
forward contracts outstanding at December 31, 1999 or 1998.
See Note 11 - Financial Instruments, Credit and Risk Management
for further discussion.
Levelization of Nuclear Refueling Outage Costs
Incremental operation and maintenance costs associated with
refueling outages at the Cook Plant are deferred commensurate with
their rate-making treatment and amortized over the period beginning
with the commencement of an outage and ending with the beginning of
the next outage.
Amortization of Cook Plant Deferred Restart Costs
Pursuant to settlement agreements approved by the IURC and the
MPSC to resolve all issues related to the extended outage of the
Cook Plant, the Company deferred certain operation and maintenance
costs in 1999. The settlement agreements provide for the deferral
of up to $150 million of Indiana jurisdictional and up to $50
million of Michigan jurisdictional non-fuel operation and
maintenance costs incurred in 1999. The deferred amount will be
amortized to expense on a straight-line basis over five years
beginning January 1, 1999. The Company deferred $200 million and
amortized $40 million in 1999 leaving $160 million as a SFAS 71
regulatory asset at December 31, 1999 on the Consolidated Balance
Sheet. See Note 2 "Cook Nuclear Plant Shutdown" for a discussion
of the settlement agreements.
Income Taxes
The Company follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income
Taxes." Under the liability method, deferred income taxes are
provided for all temporary differences between 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 (that is, deferred
taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are
recorded and related regulatory assets and liabilities are
established in accordance with SFAS 71.
Investment Tax Credits
Investment tax credits have been accounted for under the
flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral
basis. Investment tax credits that have been deferred are being
amortized over the life of regulated plant investment.
Debt and Preferred Stock
Gains and losses from the 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 debt issuance expenses are
deferred and 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 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 (SNF) are
recorded at market value in accordance with SFAS 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. Under the provisions of SFAS 71,
unrealized gains and losses from securities in these trust funds
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 SNF disposal trust
funds.
Other Property and Investments
Other property and investments are stated at cost.
Comprehensive Income
There were no material differences between net income and
comprehensive income.
Reclassification
Certain prior year amounts have been reclassified to conform to
current year presentation. Such reclassifications had no impact on
previously reported net income.
2. COOK NUCLEAR PLANT SHUTDOWN:
I&M owns and operates the two-unit 2,110 megawatt (mw) Cook
Plant under licenses granted by the Nuclear Regulatory Commission
(NRC). The Company shut down both units of the Cook Plant in
September 1997 due to questions regarding the operability of
certain safety systems that arose during a NRC architect engineer
design inspection. The NRC issued a Confirmatory Action Letter in
September 1997 requiring the Company to address certain issues
identified in the letter. In 1998 the NRC notified the Company
that it had convened a Restart Panel for Cook Plant and provided a
list of required restart activities. In order to identify and
resolve the issues necessary to restart the Cook units, the Company
is working with the NRC and will be meeting with the Panel on a
regular basis until the units are returned to service. In a
February 2, 2000 letter from the NRC, I&M was notified that the
Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to return to service in April 2000 and Unit 1 scheduled
to return to service in September 2000. The restart plan was
developed based upon a comprehensive systems readiness review of
all operating systems at the Cook Plant. When maintenance and
other work including testing required for restart are complete, the
Company will seek concurrence from the NRC to return the Cook Plant
to service. Any issues or difficulties encountered in testing of
equipment as part of the restart process could delay the scheduled
restart dates.
Replacement of the steam generator for Unit 1 will be completed
before it is returned to service. Costs associated with the steam
generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At December 31, 1999, $119 million has
been spent on the steam generator replacement.
The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal-based purchased power is being
substituted for the unavailable low cost nuclear generation. With
regulator approvals, actual replacement energy fuel costs that
exceeded the costs reflected in billings were recorded as a
regulatory asset under the Indiana and Michigan retail
jurisdictional fuel cost recovery mechanisms.
On March 30, 1999, the IURC approved a settlement agreement
that resolved all matters related to the recovery of replacement
energy fuel costs and all outage/restart costs and issues during
the extended outage of the Cook Plant. The settlement agreement
provided for, among other things, a replacement fuel billing credit
of $55 million, including interest, to Indiana retail customers'
bills; the deferral of unrecovered fuel revenues accrued between
September 9, 1997 and December 31, 1999, including the billing
credit; the deferral of up to $150 million of jurisdictional
restart related nuclear operation and maintenance costs in 1999
above the amount included in base rates; the amortization of the
deferred fuel revenues and non-fuel operation and maintenance cost
deferrals over a five-year period ending December 31, 2003; a
freeze in base rates through December 31, 2003; and a fixed fuel
recovery charge through March 1, 2004. The $55 million credit was
applied to retail customers' bills during the months of July,
August and September 1999.
On December 16, 1999, the MPSC approved a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases which resolves all issues related to the Cook Plant extended
outage. The settlement agreement limits the Company's ability to
increase base rates and freezes the power supply cost recovery
factor until January 1, 2004; permits the deferral of up to $50
million in 1999 of jurisdictional non-fuel nuclear operation and
maintenance expenses; authorizes the amortization of power supply
cost recovery revenues accrued from September 9, 1997 to December
31, 1999 and non-fuel nuclear operation and maintenance cost
deferrals over a five-year period ending December 31, 2003.
Expenditures to restart the Cook Plant units are estimated to
total approximately $574 million. Through December 31, 1999, $373
million has been spent. The restart costs incurred in 1997 and
1998 were $6 and $78 million, respectively, and were recorded in
other operation and maintenance expense. In 1999 the restart costs
incurred were $289 million and were recorded in accordance with the
Indiana and Michigan settlement agreements whereby $150 million and
$50 million, respectively, of operation and maintenance costs were
deferred in 1999 for amortization through December 31, 2003. The
amortization of the non-fuel operation and maintenance restart cost
deferrals through December 31, 1999 was $40 million. Consequently,
maintenance and other operation expenses included $129 million of
Cook restart expense for 1999. Also reflected in 1999 earnings is
amortization of $38 million of fuel-related revenues. Restart
costs incurred in 2000 will be accounted for as a current period
operations and maintenance expense. At December 31, 1999, the
unamortized balance of restart related operation and maintenance
costs was $160 million and is included in the Company's regulatory
assets. Also deferred as a regulatory asset at December 31, 1999
was $150 million of fuel-related revenues.
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and
possibly financial condition through 2003 and on cash flows through
2000. Management believes that the Cook Plant units will be
successfully returned to service by April and September 2000.
However, if for some unknown reason the units are not returned to
service or their return is delayed significantly it would have an
even greater adverse effect on future results of operations, cash
flows and financial condition.
3. RATE MATTERS:
Transmission
The FERC issued orders 888 and 889 in April 1996 which required
each public utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point
transmission tariff that offers services comparable to the
utility's own uses of its transmission system. The orders also
require utilities to functionally unbundle their services, by
requiring them to use their own transmission service tariffs in
making off-system and third-party sales. As part of the orders,
the FERC issued a pro-forma tariff which reflects the Commission's
views on the minimum non-price terms and conditions for
non-discriminatory transmission service. The FERC orders also allow a
utility to seek recovery of certain prudently-incurred stranded
costs that result from unbundled transmission service.
In July 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain pricing
issues. The 1996 tariff incorporated transmission rates which were
the result of a settlement of a pending rate case, but which were
being collected subject to refund from certain customers who
opposed the settlement and continued to litigate the reasonableness
of the AEP System's transmission rates. On July 30, 1999, the FERC
issued an order in the litigated rate case which would reduce AEP's
rates for the affected customers below the settlement rate. The
AEP System and certain of the affected customers sought rehearing
of the FERC order. The Company made a provision in September 1999
for its share of the refund including interest.
On December 10, 1999, the AEP System companies filed a
settlement agreement with the FERC resolving the issues on
rehearing of the July 30, 1999 order. Under terms of the
settlement, the AEP System will make refunds retroactive to
September 7, 1993 to certain customers affected by the July 30,
1999 FERC order. The refunds will be made in two payments. The
first payment was made on February 2, 2000 pursuant to a FERC
order granting AEP's request to make interim refunds. The
remainder will be paid after the FERC issues a final order and
approves a compliance filing that the AEP System companies will
make pursuant to the final order. In addition, a new rate was made
effective January 1, 2000, subject to FERC approval, for all
transmission service customers and a future rate was established to
take effect upon the consummation of the AEP and Central and South
West Corporation merger unless a superseding rate is made effective
prior to the merger.
Retail
In December 1997, AEP Co., Inc. and Central and South West
Corporation announced their plan to merge. As part of the
regulatory approval process, the IURC and MPSC intervened in the
FERC proceeding.
The IURC approved a settlement agreement related to the merger
on April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger initiated by the IURC. The
terms of the settlement agreement provide for, among other things,
a sharing of net merger savings for eight years through reductions
in customers' bills of approximately $67 million over eight years
following consummation of the merger; a one year extension through
January 1, 2005 of a freeze in base rates; additional annual
deposits of $6 million to the nuclear decommissioning trust fund
for the Indiana jurisdiction for the years 2001 through 2003;
quality-of-service standards; and participation in a regional
transmission organization. As part of the settlement agreement,
the IURC agreed not to oppose the merger in the FERC or SEC
proceedings.
The MPSC has also approved a settlement agreement with the
Company related to the pending merger. In approving the settlement
agreement, the MPSC has agreed to not oppose the merger at the
federal level. AEP has agreed to share net merger savings with
Michigan customers as well as AEP shareowners for eight years;
establish performance standards that will maintain or improve
customer service and system reliability; join a regional
transmission organization by December 31, 2000; and establish
affiliate rules to protect consumers and promote fair competition.
The Michigan jurisdictional customers' share of the net guaranteed
merger savings is approximately $14 million over the eight years
following the consummation of the merger. Once the merger is
consummated, Michigan customers will receive their share of the net
savings through billing credits of approximately 1 percent to 1.5
percent each year. The credits will continue for at least eight
years and will not be affected by any changes to the current
regulatory structure in Michigan.
4. EFFECTS OF REGULATION AND PHASE-IN PLANS:
In accordance with SFAS 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 in the same accounting period. 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 71 requires that the Company's regulated rates be cost-based
and the recovery of regulatory assets probable. Management has
reviewed the evidence currently available and concluded that the
Company continues to meet the requirements to apply SFAS 71. In
the event a portion of the Company's business no longer met 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 cost.
Recognized regulatory assets and liabilities are comprised of
the following at:
December 31,
1999 1998
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $236,783 $259,641
Cook Plant Restart Costs 160,000 -
Unrecovered Fuel and
Purchased Power 150,004 65,308
Department of Energy
Decontamination and
Decommissioning Assessment 35,238 38,898
Nuclear Refueling
Outage Cost Levelization 9,150 17,630
Unamortized Loss On
Reacquired Debt 14,780 16,434
Other 18,855 23,564
Total Regulatory Assets $624,810 $421,475
Regulatory Liabilities:
Deferred Investment Tax Credits $121,627 $129,779
Other* 17,238 16,507
Total Regulatory Liabilities $138,865 $146,286
* Included in Deferred Credits on Consolidated Balance
Sheets.
The Rockport Plant consists of two 1,300 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 de-
ferred and is being amortized, with related taxes and investment
tax credits, over the initial lease term which expires in 2022.
At January 1, 1997 rate phase-in plan deferrals existed for the
Rockport Plant. 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 were completed.
During the recovery period net income was unaffected by the
recovery of the phase-in deferrals. Amortization was $11.9 million
in 1997.
5. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made to support
the Company's utility operations and are estimated to be $329
million for 2000-2002.
Long-term fuel supply contracts contain clauses that provide
for periodic price adjustments. The fuel supply 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 Michigan and Indiana
retail jurisdictions, under the terms of settlement agreements have
suspended the operation of fuel clause mechanisms that provide for
recovery of changes in the cost of fuel with the regulators' review
and approval until January 2004 and March 2004, respectively.
The Company is committed under unit power agreements to
purchase all of AEGCo's share, 50% of the 2,600 mw Rockport Plant
capacity, unless it is sold to other utilities. AEGCo had a
long-term unit power agreement which expired December 31, 1999 for the
sale of 455 mw to an unaffiliated utility. Revenues received by
AEGCo under this agreement were $64 million in 1999. An agreement
between AEGCo and another affiliate provides for the sale of 390 mw
of capacity to that affiliate through 2004. Effective January 1,
2000, I&M is required to purchase 910 mw of Rockport Plant capacity
from AEGCo.
The Company sells under contract up to 250 mw of its Rockport
Plant capacity to an unaffiliated utility. The contract expires in
2009.
Nuclear Plant
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 (U.S.), the resultant liability
could be substantial. By agreement I&M is partially liable
together with all other electric utility companies that own nuclear
generating units for a nuclear power plant incident. In the event
nuclear losses or liabilities are underinsured or exceed
accumulated funds and recovery in rates is not possible, results of
operations, cash flows and financial condition would be negatively
affected.
Nuclear Incident Liability
Public liability is limited by law to $9.9 billion should an
incident occur at any licensed reactor in the U.S. Commercially
available insurance provides $200 million of coverage. In the
event of a nuclear incident at any nuclear plant in the U.S. the
remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor payable in
annual installments of $10 million. As a result, I&M could be
assessed $176 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
billion 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 unaffiliated nuclear units. The Company could be
assessed up to $23 million annually under these policies.
SNF Disposal
Federal law provides for government responsibility for
permanent SNF disposal and assesses nuclear plant owners fees for
SNF 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 $199 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, 1999, funds collected
from customers towards payment of the pre-April 1983 fee and
related earnings thereon approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposal
Decommissioning costs are being accrued over the service life
of the Cook Plant. The licenses to operate the two nuclear units
expire in 2014 and 2017. After expiration of the licenses the
plant is expected to be decommissioned through dismantlement. The
estimated cost of decommissioning and low level radioactive 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 SNF
may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the
federal government's SNF 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 amounts were $28 million in 1999, $29
million in 1998 and $28 million in 1997. Decommissioning costs
recovered from customers are deposited in external trusts. In 1999
the Company also deposited in the decommissioning trust $4 million
related to a special regulatory commission approved funding method.
Trust fund earnings increase the fund assets and the recorded
liability and decrease the amount needed to be recovered from
ratepayers. During 1999 and 1998 the Company withdrew $8 million
and $3 million, respectively, from the trust funds for
decommissioning of the original steam generators removed from Unit
2. At December 31, 1999 and 1998, the Company has recognized a
decommissioning liability of $501 million and $446 million,
respectively.
Federal EPA Complaint and Notice of Violation
Under the Clean Air Act, if a fossil plant undertakes a major
modification that directly results in an emissions increase,
permitting requirements might be triggered and the plant may be
required to install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
On November 3, 1999, the Department of Justice, at the request
of the U.S. Environmental Protection Agency (Federal EPA), filed a
complaint in the U.S. District Court for the Southern District of
Ohio that alleges the Company made modifications to generating
units at its Tanners Creek Plant over the course of the past 25
years that extend unit operating lives or increase unit generating
capacity without a preconstruction permit in violation of the Clean
Air Act. Federal EPA also issued a Notice of Violation to the
Company and other AEP companies alleging violations at certain AEP
Plants. A number of unaffiliated utilities also received Notices
of Violation, complaints or administrative orders.
The states of New Jersey, New York and Connecticut were
subsequently granted leave to intervene in the Federal EPA's action
against the Company under the Clean Air Act. On November 18, 1999,
a number of environmental groups filed a lawsuit against power
plants owned by the Company and its AEP System affiliates alleging
similar violations to those in the Federal EPA complaint and
Notices of Violation. This action has been consolidated with the
Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to
vigorously pursue its defense of this matter.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates or the future market prices of electricity if generation is
deregulated.
Litigation
The Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a ruling
from their National Office that certain interest deductions claimed
by the Company relating to AEP's corporate owned life insurance
(COLI) program should not be allowed. As a result of a suit filed
in U.S. District Court (discussed below) this request for ruling
was withdrawn by the IRS agents. Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions for
taxable years 1991-96. A disallowance of the COLI interest
deductions through December 31, 1999 would reduce earnings by
approximately $66 million (including interest).
The Company made payments of taxes and interest attributable to
COLI interest deductions for taxable years 1991-98 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are
included on the Consolidated Balance Sheets in other property and
investments pending the resolution of this matter. The Company is
seeking refunds through litigation of all amounts paid plus
interest.
In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern
District of Ohio in March 1998. In 1999 a U.S. Tax Court judge
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deduction should be disallowed.
Notwithstanding the Tax Court's decision in Winn-Dixie, management
has made no provision for any possible adverse earnings impact from
this matter because it believes, and has been advised by outside
counsel, that it has a meritorious position and will vigorously
pursue its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations, cash flows and possibly financial condition.
The Company is involved in a number of other 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.
6. SUBSEQUENT EVENT - NOx REDUCTIONS (March 3, 2000):
On March 3, 2000, the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court) issued a decision generally
upholding Federal EPA's final rule (the NOx rule) that requires
substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including the states in which the Company's
generating plants are located. A number of utilities, including the
AEP System companies, had filed petitions seeking a review of the
final rule in the Appeals Court. On May 25, 1999, the Appeals
Court had indefinitely stayed the requirement that states develop
revised air quality programs to impose the NOx reductions but did
not, however, stay the final compliance date of May 1, 2003.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to the
Clean Air Act (Section 126 Rule). The rule approved portions of
the states' petitions and imposed NOx reduction requirements on AEP
System generating units which are approximately equivalent to the
reductions contemplated by the NOx Rule. The AEP System companies
with generating plants, as well as other utility companies, filed
a petition in the Appeals Court seeking review of Federal EPA's
approval of the northeastern states' petitions. In 1999, three
additional northeastern states and the District of Columbia filed
petitions with Federal EPA similar to those originally filed by the
eight northeastern states. Since the petitions relied in part on
compliance with an 8-hour ozone standard remanded by the Appeals
Court in May 1999, Federal EPA indicated its intent to decouple
compliance with the 8-hour standard and issue a revised rule.
On December 17, 1999, Federal EPA issued a revised Section 126
Rule not based on the 8-hour standard and ordered 392 industrial
facilities, including certain coal-fired generating plants owned by
the Company, to reduce their NOx emissions by May 1, 2003. This
rule approves portions of the petitions filed by four northeastern
states which contend that their failure to meet Federal EPA smog
standards is due to emissions from upwind states' industrial and
coal-fired generating facilities.
Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required capital
expenditures of approximately $202 million for the Company. Since
compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's
preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or
reflected in the future market price of electricity if generation
is deregulated, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition.
7. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are
shared by members of the AEP Power Pool of which the Company is a
member. 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 AEP Power Pool
members based on their relative peak demands and generating
reserves. AEP Power Pool members are also compensated for the
out-of-pocket costs of energy delivered to the AEP Power Pool and
charged for energy received from the AEP Power Pool. The Company
is a net supplier to the AEP Power Pool and, therefore, receives
capacity credits from the AEP Power Pool.
Operating revenues include revenues for capacity and energy
supplied to the AEP Power Pool as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Capacity Revenues $42,575 $33,011 $ 53,282
Energy Revenues 8,049 4,550 64,861
Total $50,624 $37,561 $118,143
Purchased power expense includes charges of $112.3 million in
1999, $125.2 million in 1998 and $51 million in 1997 for energy
received from the AEP Power Pool.
The AEP Power Pool allocates operating revenues, purchased
power expense and nonoperating income to the Company. Power
marketing and trading operations, which are described in Note 1,
are conducted by the AEP Power Pool and shared with the Company.
Net trading transactions are included in operating revenues if the
trading transactions are within the AEP Power Pool's traditional
marketing area and are recorded in nonoperating income if the net
trading transactions are outside of the AEP Power Pool's
traditional marketing area. The total amount allocated by the AEP
Power Pool, which includes amounts for power marketing and trading
transactions, are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Operating Revenues $81,659 $124,973 $74,895
Purchased Power Expense 66,285 71,588 15,415
Nonoperating Income (Loss) 2,104 (7,122) (61)
The cost of Rockport Plant power purchased from AEGCo, an
affiliated company that is not a member of the AEP Power Pool, was
included in purchased power expense in the amounts of $88.1
million, $86.2 million and $87.5 million in 1999, 1998 and 1997,
respectively.
The cost of power purchased from Ohio Valley Electric
Corporation, an affiliated company that is not a member of the AEP
Power Pool, was included in purchased power expense in the amounts
of $10.2 million, $14.3 million and $11 million in 1999, 1998 and
1997, respectively.
The Company operates the Rockport Plant and bills AEGCo for its
share of operating costs.
The Company participates in the AEP System Transmission
Equalization Agreement along with other AEP System electric
operating utility companies. 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 $43.9 million, $44.1 million and
$46.1 million in 1999, 1998 and 1997, respectively.
Revenues from providing barging services were recorded in
nonoperating income as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Affiliated Companies $28,100 $23,494 $24,427
Unaffiliated Companies 15,700 12,490 8,383
Total $43,800 $35,984 $32,810
American Electric Power Service Corporation (AEPSC) provides
certain managerial and professional services to AEP System
companies including the Company. The costs of the services are
billed by AEPSC to its affiliated companies on a direct-charge
basis whenever possible and on reasonable bases of proration for
shared services. The billings 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.
8. STAFF REDUCTIONS:
During 1998 an internal evaluation of the power generation
organization was conducted with a goal of developing an optimum
organizational structure for a competitive generation market. The
study was completed in October 1998. In addition, a review of
energy delivery staffing levels was conducted in 1998. As a result
approximately 80 power generation and energy delivery positions
were identified for elimination.
A provision for severance costs totaling $3.7 million was
recorded in December 1998 for reductions in power generation and
energy delivery staffs and was charged to maintenance and other
operation expense in the Consolidated Statements of Income. The
power generation and energy delivery staff reductions were made in
the first quarter of 1999. The amount of severance benefits paid
was not significantly different from the amount accrued.
9. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System
qualified pension plan, a defined benefit plan which covers all
employees. Net pension (credits) costs for the years ended
December 31, 1999, 1998 and 1997 were $(1.3) million, $2.1 million
and $2.1 million, respectively.
Postretirement benefits other than pensions are provided for
retired employees for medical and death benefits under an AEP
System plan. The Company's annual accrued costs for 1999, 1998 and
1997 were $13.7 million, $12 million and $11.5 million,
respectively.
A defined contribution employee savings plan required that the
Company make contributions to the plan totaling $4 million each
year in 1999, 1998 and 1997.
10. SEGMENT INFORMATION:
Effective December 31, 1998, the Company adopted SFAS 131,
"Disclosures about Segments of an Enterprise and Related
Information". The Company has one reportable segment, a regulated
vertically integrated electricity generation and energy delivery
business. All other activities are insignificant. The Company's
operations are managed on an integrated basis because of the
substantial impact of bundled cost-based rates and regulatory
oversight on business processes, cost structures and operating
results. Aggregated in the regulated electric utility segment is
the power marketing and trading activities that are discussed in
Note 1. For the years ended December 31, 1999, 1998 and 1997, all
revenues are derived in the U.S.
11. FINANCIAL INSTRUMENTS, CREDIT AND RISK MANAGEMENT:
The Company is subject to market risk as a result of changes in
electricity commodity prices and interest rates. The Company
through its membership in the AEP Power Pool participates in a
power marketing and trading operation that manages the exposure to
electricity commodity price movements using physical forward
purchase and sale contracts at fixed and variable prices, and
financial derivative instruments including exchange traded futures
and options, over-the-counter options, swaps and other financial
derivative contracts at both fixed and variable prices. Physical
forward electricity contracts within the AEP Power Pool's
traditional marketing area are recorded on a net basis as operating
revenues in the month when the physical contract settles. The
Company's share of the net gains from these regulated transactions
for the year ended December 31, 1999 and 1998 was $4 million and
$21 million, respectively. These activities were not material in
1997.
Non-regulated physical forward electricity contracts outside
the AEP Power Pool's traditional marketing area and all financial
electricity trading transactions where the underlying physical
commodity is outside AEP's traditional marketing area are recorded
in nonoperating income. Non-regulated open trading contracts are
accounted for on a mark-to-market basis in nonoperating income.
The Company's share of the net gains (losses) from these
non-regulated trading transactions for the year ended December 31, 1999
and 1998 was $2 million and $(7) million, respectively.
In the first quarter of 1999 the Company adopted EITF 98-10
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities." The EITF requires that all energy trading
contracts be marked-to-market. The effect on the consolidated
Statements of Income of marking open trading contracts to market is
deferred as regulatory assets or liabilities for those open trading
transactions within the AEP Power Pool's marketing area that are
included in the cost of service on a settlement basis for
rate-making purposes. The unrealized mark-to-market gains and losses
from trading of financial instruments are reported as assets and
liabilities, respectively. These activities were not material in
prior periods.
The Company is exposed to risk from changes in interest rates
primarily due to short-term and long-term borrowings used to fund
its business operations. The debt portfolio has both fixed and
variable interest rates with terms from one day to 39 years and an
average duration of five years at December 31, 1999. A near term
change in interest rates should not materially affect results of
operations or financial position since the Company would not expect
to liquidate its entire debt portfolio in a one year holding
period.
Market Valuation
The book value 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. The
book value of the pre-April 1983 spent nuclear fuel disposal
liability approximates the Company's best estimate of its fair
value.
The book value amounts and fair values of the Company's
significant financial instruments at December 31, 1999 and 1998 are
summarized in the following table. The fair values of long-term
debt and preferred stock 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 fair
value of those financial instruments that are marked-to-market are
based on management's best estimates using over-the-counter
quotations, exchange prices, volatility factors and valuation
methodology. The estimates presented herein are not necessarily
indicative of the amounts that the Company could realize in a
current market exchange.
1999 1998
Book Value Fair Value Book Value Fair Value
(in thousands) (in thousands)
Non-Derivatives
Long-term Debt $1,324,326 $1,283,300 $1,175,789 $1,235,200
Preferred Stock 64,945 63,500 68,445 72,600
Derivatives
1999 1998
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
(Dollars in thousands)
Trading Assets
GWH GWH
Electric
NYMEX Futures
and Options 43 $ 340 $ 171 - $ - $ -
Physicals 13,592 112,830 99,621 11,097 8,700 7,700
Options 1,213 8,010 12,125 734 6,300 15,300
Swaps 35 76 61 52 600 200
Trading Liabilities
GWH GWH
Electric
NYMEX Futures
and Options - $ - $ - 133 $(1,300) $ (300)
Physicals 14,620 (105,169) (95,948) 10,932 (9,400) (8,800)
Options 1,742 (8,391) (11,010) 557 (5,700) (15,200)
Swaps 35 (70) (58) 93 (1,400) (400)
Credit and Risk Management
In addition to market risk associated with price movements, the
Company through the AEP Power Pool is also subject to the credit
risk inherent in its risk management activities. Credit risk
refers to the financial risk arising from commercial transactions
and/or the intrinsic financial value of contractual agreements with
trading counter parties, by which there exists a potential risk of
nonperformance. The AEP Power Pool has established and enforced
credit policies that minimize this risk. The AEP Power Pool
accepts as counter parties to forwards, futures, and other
derivative contracts primarily those entities that are classified
as Investment Grade, or those that can be considered as such due to
the effective placement of credit enhancements and/or collateral
agreements. Investment grade is the designation given to the four
highest debt rating categories (i.e., AAA, AA, A, BBB) of the major
rating services, e.g., ratings BBB- and above at Standard & Poor's
and Baa3 and above at Moody's. When adverse market conditions have
the potential to negatively affect a counter party's credit
position, the AEP Power Pool requires further credit enhancements
to mitigate risk. Since the formation of the power marketing and
trading business in July of 1997, the Company has experienced no
significant losses due to the credit risk associated with risk
management activities; furthermore, the Company does not anticipate
any future material effect on its results of operations, cash flow
or financial condition as a result of counter party nonperformance.
Nuclear Trust Funds Recorded at Market Value
The Nuclear Decommissioning and SNF 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, 1999 and 1998 the fair values of trust fund
investments were $708 million and $648 million, respectively.
Accumulated gross unrealized holding gains were $78 million and $65
million and accumulated gross unrealized holding losses were $6.7
million and $1.1 million at December 31, 1999 and 1998,
respectively. The change in market value in 1999, 1998 and 1997
was a net unrealized holding gain of $7.5 million, $24 million and
$19.1 million, respectively.
The trust fund investments' cost basis by security type were:
December 31,
1999 1998
(in thousands)
Tax-Exempt Bonds $350,798 $326,239
Equity Securities 116,110 95,854
Treasury Bonds 72,927 71,194
Corporate Bonds 13,162 10,661
Cash, Cash Equivalents
and Interest Accrued 83,129 80,065
Total $636,126 $584,013
Proceeds from sales and maturities of securities of $226
million during 1999 resulted in $5.8 million of realized gains and
$5.3 million of realized losses. Proceeds from sales and
maturities of securities of $225 million during 1998 resulted in
$8.2 million of realized gains and $2.8 million of realized losses.
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. The cost of securities for determining
realized gains and losses is original acquisition cost including
amortized premiums and discounts.
At December 31, 1999, the year of maturity of trust fund
investments, other than equity securities, was:
(in thousands)
2000 $120,630
2001-2004 173,851
2005-2009 181,860
After 2009 43,675
Total $520,016
12. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1999 1998 1997
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $(60,238) $ 38,165 $ 75,442
Deferred 85,345 21,073 3,088
Deferred Investment Tax Credits (7,547) (7,593) (7,786)
Total 17,560 51,645 70,744
Charged (Credited) to Nonoperating Income (net):
Current 1,529 (594) 3,287
Deferred 382 (3,168) 834
Deferred Investment Tax Credits (605) (673) (642)
Total 1,306 (4,435) 3,479
Total Federal Income Taxes as Reported $ 18,866 $ 47,210 $ 74,223
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,
1999 1998 1997
(in thousands)
Net Income $ 32,776 $ 96,628 $146,740
Federal Income Taxes 18,866 47,210 74,223
Pre-tax Book Income $ 51,642 $143,838 $220,963
Federal Income Tax on Pre-tax Book Income at
Statutory Rate (35%) $18,075 $50,343 $77,337
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Depreciation 19,966 17,257 14,082
Corporate Owned Life Insurance 594 (3,263) (3,348)
Nuclear Fuel Disposal Costs (3,347) (3,397) (3,286)
AFUDC (2,174) (2,184) (1,987)
Investment Tax Credits (net) (8,152) (8,266) (8,428)
Other (6,096) (3,280) (147)
Total Federal Income Taxes as Reported $18,866 $47,210 $74,223
Effective Federal Income Tax Rate 36.5% 32.8% 33.6%
The following tables show the elements of the net deferred tax
liability and the significant temporary differences giving rise to
such deferrals:
December 31,
1999 1998
(in thousands)
Deferred Tax Assets $ 231,329 $ 226,118
Deferred Tax Liabilities (853,486) (785,406)
Net Deferred Tax Liabilities $(622,157) $(559,288)
Property Related
Temporary Differences $(436,162) $(460,077)
Amounts Due From Customers
For Future Federal
Income Taxes (61,311) (69,102)
Deferred State Income Taxes (61,700) (62,302)
Deferred Gain on Sale and
Leaseback of Rockport
Plant Unit 2 29,752 31,049
Accrued Nuclear
Decommissioning Expense 32,097 29,930
Deferred Fuel and
Purchased Power (52,713) (22,737)
Deferred Cook Plant
Restart Costs (56,000) -
All Other (net) (16,120) (6,049)
Net Deferred Tax Liabilities $(622,157) $(559,288)
The Company and its subsidiaries join in the filing of a
consolidated federal income tax return with their affiliates in the
AEP System. The allocation of the AEP System's current
consolidated federal income tax to the 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 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 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 being audited by the IRS. With the exception of interest
deductions related to COLI, which are discussed under the heading
"Litigation" in Note 5, management is not aware of any issues for
open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.
13. CUMULATIVE PREFERRED STOCK:
At December 31, 1999, 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.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1999 Value Year Ended December 31, December 31, 1999 1999 1998
1999 1998 1997 (in thousands)
4-1/8% $106.125 $100 97 771 59,760 59,139 $5,914 $5,924
4.56% 102 100 150 650 44,788 14,412 1,441 1,456
4.12% 102.728 100 - 200 20,869 18,931 1,893 1,893
$9,248 $9,273
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, 1999 1999 1998
1999 1998 1997 (in thousands)
5.90% (b) $100 15,000 - 233,000 152,000 $15,200 $16,700
6-1/4%(b) 100 10,000 - 97,500 192,500 19,250 20,250
6.30% (b) 100 - - 217,550 132,450 13,245 13,245
6-7/8%(c) 100 10,000 - 117,500 172,500 17,250 18,250
$64,945 $68,445
(a) Not callable until after 2002. There are no aggregate sinking
fund provisions through 2002. Sinking fund provisions require the
redemption of 15,000 shares in 2003 and 67,500 shares in 2004.
(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 1999 and 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 1999 and
1997 may be applied to meet the sinking fund requirement.
14. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1999 1998
(in thousands)
First Mortgage Bonds $ 356,820 $ 466,330
Installment Purchase
Contracts 309,568 309,418
Senior Unsecured Notes 297,282 48,559
Other Long-term Debt (a) 199,259 190,192
Junior Debentures 161,397 161,290
1,324,326 1,175,789
Less Portion Due Within
One Year 198,000 35,000
Total $1,126,326 $1,140,789
(a) Represents a SNF disposal liability including interest accrued
payable to the Department of Energy. See Note 5.
First mortgage bonds outstanding were as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
7.30 1999 - December 15 $ - $ 35,000
6.40 2000 - March 1 48,000 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
6.55 2003 - October 1 - 20,000
6.10 2003 - November 1 30,000 30,000
6.55 2004 - March 1 - 25,000
8.50 2022 - December 15 75,000 75,000
7.35 2023 - October 1 20,000 20,000
7.20 2024 - February 1 30,000 40,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (net) (1,180) (1,670)
356,820 466,330
Less Portion Due Within One Year 48,000 35,000
Total $308,820 $431,330
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,
1999 1998
(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 (2,432) (2,582)
309,568 309,418
Less Portion Due Within
One Year 50,000 -
Total $259,568 $309,418
(a) A variable interest rate is determined weekly. The average
weighted interest rate was 3.2% for 1999 and 4.1% for 1998.
(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 2.2% to 5.6% in 1999 and
from 2.7% to 4.3% in 1998 and averaged 3.2% and 3.6% during
1999 and 1998, 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.
Senior unsecured notes outstanding were as follows:
December 31,
1999 1998
(in thousands)
% Rate Due
(a) 2000 - November 22 $100,000 $ -
6-7/8 2004 - July 1 150,000 -
6.45 2008 - November 10 50,000 50,000
Unamortized Discount (2,718) (1,441)
297,282 48,559
Less Portion Due Within One Year 100,000 -
Total $197,282 $48,559
(a) A floating interest rate is determined monthly. The rate on
December 31, 1999 was 7.1%.
Junior debentures are composed of the following:
December 31,
1999 1998
(in thousands)
% Rate Due
8.00 2026 - March 31 $ 40,000 $ 40,000
7.60 2038 - June 30 125,000 125,000
Unamortized Discount (3,603) (3,710)
Total $161,397 $161,290
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, 1999, future annual long-term debt payments
are as follows:
Amount
(in thousands)
2000 $ 198,000
2001 40,000
2002 140,000
2003 30,000
2004 150,000
Later Years 776,259
Total Principal Amount 1,334,259
Unamortized Discount (9,933)
Total $1,324,326
Short-term debt borrowings are limited by provisions of the
1935 Act to $500 million. Lines of credit are shared with AEP
System companies and at December 31, 1999 were available in the
amounts of $1,056 million. The short-term lines of credit require
the payment of facility fees and do not require compensating
balances. At December 31, 1999 and 1998, outstanding short-term
debt consisted of commercial paper with year-end weighted average
interest rates of 6.6% and 6.2%, respectively.
15. 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 majority of the leases have
purchase or renewal options and will be renewed or replaced by
other leases. The Company is leasing 50% of the 1,300 mw Rockport
2 generating unit under an operating lease. The lease has 23 years
remaining and total minimum lease payments of $1.7 billion.
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,
1999 1998 1997
(in thousands)
Lease Payments on
Operating Leases $ 81,611 $ 88,297 $ 92,067
Amortization of Capital Leases 11,320 10,717 42,882
Interest on Capital Leases 9,338 10,302 9,737
Total Lease Rental Costs $102,269 $109,316 $144,686
Properties under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
December 31,
1999 1998
(in thousands)
Electric Utility Plant Under Capital Leases:
Production Plant $ 8,348 $ 8,850
Transmission Plant 4 -
Distribution Plant 14,645 14,645
General Plant:
Nuclear Fuel (net of amortization) 108,140 103,939
Other Plant 59,150 60,002
Total Electric Utility Plant
Under Capital Leases 190,287 187,436
Accumulated Amortization 35,176 33,948
Net Electric Utility Plant
Under Capital Leases 155,111 153,488
Other Property Under Capital Leases 40,213 37,672
Accumulated Amortization 7,359 4,733
Net Other Property Under Capital Leases 32,854 32,939
Net Properties Under Capital Leases $187,965 $186,427
Capital Lease Obligations*:
Noncurrent Liability $176,893 $176,760
Liability Due Within One Year 11,072 9,667
Total Capital Lease Obligations $187,965 $186,427
* Represents the present value of future minimum lease payments.
The noncurrent portion of capital lease obligations is
included in other noncurrent liabilities on the Consolidated
Balance Sheets. Properties under operating leases and related
obligations are not included on the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at
December 31, 1999:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
2000 $ 15,186 $ 100,288
2001 13,535 99,061
2002 16,116 97,341
2003 10,259 97,207
2004 8,641 96,395
Later Years 38,808 1,528,873
Total Future Minimum
Lease Payments 102,545 (a) $2,019,165
Less Estimated
Interest Element 22,720
Estimated Present
Value of Future
Minimum Lease
Payments 79,825
Unamortized Nuclear
Fuel 108,140
Total $187,965
(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.
16. 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, 1999, $5.9 million of retained earnings
were restricted. Regulatory approval is required to pay dividends
out of paid-in capital.
In 1999, 1998 and 1997 net changes to paid-in capital of
$134,000, $133,000 and $1,200,000 respectively, represented gains
and expenses associated with cumulative preferred stock
transactions.
17. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1999 1998 1997
(in thousands)
Cash was paid (received) for:
Interest (net of
capitalized amounts) $ 78,703 $66,313 $ 62,274
Income Taxes (71,395) 36,413 120,212
Noncash Acquisitions
Under Capital Leases 10,852 9,658 111,395
18. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Net
Quarterly Periods Operating Operating Income
Ended Revenues Income (Loss)
(in thousands)
1999
March 31 $334,113 $38,838 $20,070
June 30 336,553 26,966 9,745
September 30 411,248 26,085 8,084
December 31 312,205 16,763 (5,123)
1998
March 31 328,468 51,368 33,744
June 30 348,271 42,194 28,536
September 30 412,908 58,639 38,691
December 31 316,147 13,806 (4,343)
Fourth quarter 1999 and 1998 net loss declined primarily as a
result of expenditures to prepare the nuclear units for restart.
Fourth quarter 1999 operating income include a favorable adjustment
of $21 million net of tax from the deferral of Cook Plant restart
expenses net of amortization under the terms of a Michigan
jurisdiction settlement agreement approved on December 16, 1999
(see Note 2 for details).