Selected Consolidated Financial Data
Year Ended December 31,
1993 1992 1991 1990 1989
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,202,643 $1,196,755 $1,225,867 $1,271,514 $1,135,587
Operating Expenses 992,723 1,001,235 998,578 1,070,023 921,604
Operating Income 209,920 195,520 227,289 201,491 213,983
Nonoperating Income (Loss) (234) 14,115 (3,721) 7,557 32,737
Income Before Interest Charges 209,686 209,635 223,568 209,048 246,720
Interest Charges 80,373 85,687 86,636 90,657 107,483
Net Income 129,313 123,948 136,932 118,391 139,237
Preferred Stock Dividend
Requirements 14,225 15,417 15,417 15,587 18,048
Earnings Applicable to
Common Stock $ 115,088 $ 108,531 $ 121,515 $ 102,804 $ 121,189
December 31,
1993 1992 1991 1990 1989
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,290,957 $4,266,480 $4,135,820 $4,066,227 $3,969,602
Accumulated Depreciation and
Amortization 1,714,829 1,631,438 1,521,349 1,421,285 1,309,072
Net Electric Utility Plant $2,576,128 $2,635,042 $2,614,471 $2,644,942 $2,660,530
Regulatory Assets (a) $ 492,822 $ 268,816 $ 204,060 $ 240,754 $ 280,768
Total Assets $3,765,458 $3,645,798 $3,481,878 $3,501,925 $4,125,534
Common Stock and Paid-in
Capital $ 791,517 $ 782,741 $ 782,741 $ 782,741 $ 782,741
Retained Earnings 177,638 171,309 169,243 150,408 162,213
Total Common Shareowner's
Equity $ 969,155 $ 954,050 $ 951,984 $ 933,149 $ 944,954
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 87,000 $ 197,000 $ 197,000 $ 197,000 $ 197,000
Subject to Mandatory
Redemption (b) 100,000 - - - 18,030
Total Cumulative Preferred
Stock $ 187,000 $ 197,000 $ 197,000 $ 197,000 $ 215,030
Long-term Debt (b) $1,073,154 $1,211,623 $1,130,709 $1,133,833 $1,532,736
Obligations Under Capital
Leases (b) $ 98,753 $ 126,689 $ 102,985 $ 133,447 $ 123,361
Total Capitalization and
Liabilities $3,765,458 $3,645,798 $3,481,878 $3,501,925 $4,125,534
(a) Effective January 1, 1993 a new accounting standard Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, was adopted
resulting in an increase in regulatory assets. (See Note 1 of Notes to
Consolidated Financial Statements).
(b) Including portion due within one year.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Net Income Increases
Net income increased 4.3% in 1993 and decreased 9.5% in 1992. The
scheduled refueling of the two nuclear generating units and an unscheduled
outage at one of the units in 1992 required the purchase of more expensive
replacement power from the AEP System Power Pool (Power Pool) and reduced
wholesale sales to the Power Pool reducing net income in 1992. The return to
service of the nuclear units along with the retirement and the refinancing of
debt at lower interest rates was responsible for the increase in net income
in 1993.
Outlook
The electric utility industry is expected to undergo significant changes
for the remainder of the decade because of increasing competition in the
generation and sale of electricity and increasing energy flows resulting from
open transmission access. Although management believes that the Company is
well positioned, as a low cost producer, to compete, efforts will continue to
further reduce costs and increase effectiveness.
The Company faces additional challenges from compliance with the Clean
Air Act Amendments of 1990, other environmental concerns and costs, the cost
of operating, maintaining and eventually decommissioning the two nuclear
generating units and the disposal of their spent nuclear fuel that could
affect financial performance and possibly the ability to meet financial
obligations and commitments. While management believes the Company is
equipped to meet these challenges, future financial performance is heavily
dependent on the ability to obtain favorable rate-making treatment to recover
costs of service on a timely basis.
Future results of operations will be affected by several factors,
including the continued economic health of our service territory, the
weather, competition for wholesale sales, new environmental laws and
regulations and the rate-making policies of the Company's regulators. Many
of these factors are not generally within management's direct control yet
every effort will be made to work with regulators, government officials, and
current and prospective customers to positively influence these critical
factors and to take advantage of the opportunities increased
competition will bring.
Operating Revenues and Energy Sales
Operating revenues increased $6 million in 1993 following a decline of $29
million in 1992. The 1993 increase and the 1992 decrease were attributable
to the Donald C. Cook Nuclear Plant (Cook Plant) generating units being out
of service for scheduled refueling and maintenance and an unscheduled outage
in 1992 which reduced the amount of energy the Company had available for sale
to the Power Pool.
The changes in revenues can be analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1993 1992
Amount % Amount %
Retail:
Price variance $ (75.1) $ 42.3
Volume variance 40.3 3.0
(34.8) (4.3) 45.3 5.9
Wholesale:
Price variance (137.2) 75.2
Volume variance 172.7 (141.9)
35.5 9.6 (66.7) (15.3)
Other Operating Revenues 5.2 (7.7)
Total $ 5.9 0.5 $ (29.1) (2.4)
The unfavorable retail and wholesale price variances in 1993 reflect the
operation of fuel and power supply cost recovery mechanisms due to the
availability of the Cook Plant and lower average cost generation. Under the
retail jurisdictional fuel clauses, revenues were accrued in 1992 for future
recovery of higher cost replacement power during the nuclear outages.
The increase in 1993 retail sales volume reflects continuing improvement
in industrial sales, a return to normal weather and moderate growth in
residential and commercial customer classes. The increase in wholesale sales
volume in 1993 resulted from the increased availability of energy for
delivery to the Power Pool due to availability of the Cook Plant as well as
increased sales by the Power Pool to unaffiliated utilities which the Company
shares as a member of the Pool.
The substantial retail and wholesale price variance in 1992 resulted from
recovery of higher fossil fuel generation costs and power pool purchases
which were incurred during the Cook Plant outages. The reduction in 1992
wholesale sales volume reflects a decrease in sales to the Power Pool because
of the Cook Plant outages and reduced wholesale sales by the Power Pool.
Efforts to improve short-term wholesale sales are affected by the highly
competitive nature of the short-term energy market and other factors such as
unaffiliated generating plant availability, the weather and the economy, that
are not generally within management's control. Future results of operations
will be affected by the ability to make cost-effective wholesale sales or, if
such sales are reduced, the ability to timely raise retail rates.
Operating Expenses Decline
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1993 1992
Amount % Amount %
Fuel $ 26.4 13.6 $(57.5) (22.9)
Purchased Power (72.0) (40.0) 57.8 47.1
Other Operation 12.6 5.0 5.0 2.0
Maintenance 4.9 3.5 18.5 15.6
Depreciation and
Amortization 5.4 4.1 1.1 0.8
Amortization of Rockport
Plant Unit 1 Phase-in
Plan Deferrals (0.7) (4.0) (0.7) (3.9)
Taxes Other Than
Federal Income Taxes 5.7 9.2 (0.6) (0.9)
Federal Income Taxes 9.2 36.1 (20.9) (45.1)
Total $ (8.5) (0.9) $ 2.7 0.3
Fuel expense increased in 1993 due to the significant increase in nuclear
generation and a 6% increase in fossil generation, partially offset by a de-
crease in the average cost of fuel. The reduction in fuel expense in 1992
resulted largely from reduced generation due to outages at the two nuclear
units as well as lower average fossil fuel costs.
The decline in purchased power expense in 1993 reflects a reduced level of
energy receipts from the Power Pool because of the increased availability of
the nuclear units and reduced power purchases from AEP Generating Company as
a result of Rockport Plant maintenance outages. The increase in purchased
power expense in 1992 was the result of an increased level of energy receipts
from the Power Pool during the nuclear outages.
Certain other operation and maintenance procedures can be performed only
when a nuclear unit is out of service. Therefore, during the 1992 nuclear
refueling outages, significant other operation and maintenance expenses were
incurred. However, the impact on 1992 earnings from refueling outages was
mitigated through the implementation of levelized accounting in 1992.
Levelized accounting spreads the incremental cost of refueling outages so
that the cost of an average number of refuelings are reflected in each year's
expenses. The Company received regulatory approval to defer incremental
nuclear refueling outage costs and to amortize them from the start of an
outage until the beginning of the next outage. As a result, 1993 operating
expenses include the amortization of $35.2 million of incremental nuclear
refueling outage expenses that were deferred in 1992.
Taxes other than federal income taxes increased in 1993 primarily due to
a substantial increase in Indiana supplemental net income tax because the
nuclear refueling outage costs incurred in 1992 were tax deductible in that
year. There were no refueling outages in 1993. Federal income taxes
attributable to operations increased in 1993 due to an increase in pre-tax
operating income and a reduction in interest charges. The decline in federal
income taxes attributable to operations in 1992 reflects a decrease in pre-
tax operating income.
Nonoperating Income and Financing Costs Decline
Nonoperating income declined in 1993 due to the implementation of
Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes, the recordation in 1992 of interest income on federal income tax re-
funds in connection with the settlement of audits of prior years' tax returns
and the reversal of a provision in 1992 as a result of the successful
settlement of a coal royalty dispute with the state of Utah.
Interest expense declined in 1993 due to the retirement of $142 million
of long-term debt and the refinancing of $150 million of long-term debt and
$97 million of installment purchase contracts (IPC) at lower interest rates.
The decline in 1992 was largely attributable to the refinancing of $25
million of IPCs and a lower average interest rate on a variable rate IPC.
Accrued Utility Revenues and Taxes Accrued
At December 31, 1992 under retail fuel and power supply cost recovery
mechanisms, $38 million of fuel revenues were accrued related to fuel and
replacement power costs incurred during the nuclear unit outages. Both re-
tail jurisdictions approved recovery. Recovery was completed in the Indiana
jurisdiction and substantially completed in the Michigan jurisdiction in 1993
reducing the accrued utility revenues balance at December 31, 1993. The
remaining balance in the Michigan jurisdiction will be recovered in 1994.
Taxes accrued increased in 1993 reflecting the effects of federal income
tax return audit settlements recorded in 1992. A significant refund
resulting from the audit caused a reduction in the 1992 balance.
Regulatory Assets and Deferred
Tax Liabilities Increase
The Company prospectively adopted a new accounting standard for income
taxes on January 1, 1993. The new standard required, among other things,
that regulated entities record deferred tax liabilities on temporary differ-
ences previously flowed-through for rate-making and book accounting. Where
rate-making provides for flow-through treatment, corresponding regulatory
assets were recorded resulting in an increase in total assets and
liabilities.
Construction Spending
Gross plant and property additions were $125 million in 1993 and $176
million in 1992. Management estimates construction expenditures for the next
three years to be $410 million. The funds for construction of new facilities
and improvement of existing facilities come from a combination of internally
generated funds, short-term and long-term borrowings and investments in
common equity by the Company's parent, American Electric Power Company, Inc.
(AEP Co., Inc.). Approximately 92% of the construction expenditures for the
next three years will be financed internally with the remainder financed
externally.
Capital Resources
The Company generally issues short-term debt to provide for interim
financing of capital expenditures that exceed internally generated funds. At
December 31, 1993, unused short-term lines of credit of $537 million shared
with other AEP System companies were available. Short-term borrowings
increased by $5.9 million in 1993. A charter provision limits short-term
borrowings to $127 million. Periodic reductions of outstanding short-term
debt are made through issuance of long-term debt and preferred stock and
through equity capital contributions by the parent company.
The Company received or has requested regulatory approval to issue up to
$185 million of long-term debt and preferred stock. Management expects to
use the proceeds to retire short-term debt, refinance higher cost and
maturing long-term debt, refund cumulative preferred stock and fund
construction expenditures.
Unless the Company meets certain earnings or coverage tests, additional
long-term debt or preferred stock cannot be issued. In order to issue long-
term debt without refunding an equal amount of existing debt, pre-tax
earnings must be equal to at least twice annual interest charges on long-term
debt after giving effect to the new debt. To issue additional preferred
stock, after-tax gross income must be at least equal to one and one-half
times annual interest and preferred stock dividend requirements after giving
effect to the new preferred stock. The Company presently exceeds these
minimum coverage requirements. At December 31, 1993, long-term debt and
preferred stock coverage ratios were 4.59 and 2.48, respectively.
Recently a major credit rating agency reevaluated the credit worthiness
of companies in the electric utility industry based on perceived risk from
deregulation, increased competition, reduced load growth, escalating nuclear
plant costs and environmental concerns. The agency lowered its ratings
outlook for approximately one-third of the companies but not for Indiana
Michigan Power which was regarded by the agency as being relatively well
positioned to meet future competitive challenges.
Competition
Since 1990, the short-term wholesale energy market has been extremely
competitive. With the passage of the Energy Policy Act of 1992, which
provides for greater ease of transmission access and reduces certain regula-
tory restrictions for independent power producers (IPPs), competition is
expected to increase in the long-term wholesale market and in the
construction of new generating capacity. For example, IPPs are no longer
required to find an industrial host to utilize the steam by-product from the
generation of electricity to build a generating unit and avoid regulation
under the Public Utility Holding Company Act of 1935 (1935 Act). The Energy
Policy Act also exempts IPPs from requirements under the 1935 Act which,
among other things, permit IPPs to use greater amounts of lower cost debt
which may reduce overall cost of capital. Thus IPPs may have a competitive
advantage. Although the Energy Policy Act specifically prohibits the Federal
Energy Regulatory Commission from ordering retail transmission access, the
states can do so and many believe that the next logical step will be the
extension of competition for existing industrial customers which will present
both opportunities and challenges for the Company.
Although management believes that the Company is well positioned to
compete in this evolving competitive market because of its technical skills
and expertise and its position as a low cost producer, we intend to continue
to examine ways to improve the Company's competitive position. Efforts to
improve operations and reduce costs will continue in order to maintain and
enhance our position as a low cost producer.
Although management may have opportunities to improve shareholder value
through increased competition as a result of open transmission access and
other provisions of the Energy Policy Act of 1992, there is risk and
uncertainty, especially for retail ratepayers and shareholders, regarding
reliability of future transmission service and fair compensation for use of
the Company's extensive high voltage transmission facilities. Management's
goal is to ensure that, to the extent the Company's facilities are used by
others, there is fair and appropriate compensation.
Environmental Concerns and Cost Pressures
Clean Air Act
The Clean Air Act Amendments of 1990 (CAAA) require, among other things,
substantial reductions in sulfur dioxide and nitrogen oxides emitted from
electric generating plants.
Two of the Company's generating units, Tanners Creek Unit 4 and the
Breed Plant, are affected by the first phase of the CAAA. Tanners Creek Unit
4 will comply by fuel switching at minimal capital cost. Management decided
early in 1994 to close the 325 megawatt (mw) Breed Plant as of March 31,
1994, due to its design and age (commercial operation began in 1960) as well
as the additional cost of complying with the CAAA.
The closing of the Breed Plant is not expected to adversely affect
results of operations or financial condition except as it impacts ongoing
Power Pool credits and charges.
The ongoing earnings effect of closing the Breed Plant will be that the
Company will receive less capacity credits for being a net supplier to the
Power Pool, partially offset by a reduction in operation, maintenance and
depreciation expenses. As of December 31, 1993 the unfavorable effect on
earnings is expected to be $10 million annually. The Company will seek re-
covery of this additional cost in future rate cases.
Phase II of the CAAA, effective in the year 2000, will require further
actions to comply. Additional costs will be incurred and recovery from
customers will be sought for all CAAA costs.
Global Warming
Concern about global climate change, or "the greenhouse effect" has been
the focus of intensive debate within the United States and around the world.
Much of the uncertainty about what effects greenhouse gas concentrations will
have on the global climate results from a myriad of factors that affect
climate. Based on the terms of a 1992 United Nations treaty that pledged the
United States to reduce greenhouse gas emissions, the Clinton Administration
developed a voluntary plan to reduce by the year 2000 greenhouse gas emis-
sions to 1990 levels. The AEP System supports the plan and will work with
the U.S. Department of Energy (DOE) and other electric utility companies to
formulate a cost effective framework for limiting future greenhouse gas
emissions.
The AEP System strongly supports a policy of proactive environmental
stewardship, whereby actions are taken that make economic and environmental
sense on their own merits, irrespective of the uncertain threat of global
climate change. To reduce emissions, we support energy conservation
programs, development of more efficient generation and end-use technologies,
and forest management activities because they are cost effective and bring
long-term benefits to our service area. Should significant new measures to
control the burning of coal be enacted, they could affect the Company's
competitiveness and, if not recovered from customers, adversely impact
results of operations and financial condition.
EMF
The potential for electric and magnetic fields (EMF) from transmission
and distribution facilities to adversely affect the public health is being
extensively researched. The AEP System continues to support EMF research to
help determine the extent, if any, to which EMF may adversely impact public
health. Our concern is that new laws imposing EMF limits may be passed or
new regulations promulgated without sufficient scientific study and evidence
to support them. As long as there is uncertainty about EMF, we will have
difficulty finding acceptable sites for our transmission facilities, which
could hamper economic growth within our service area. If the present energy
delivery system must be changed because of EMF concerns, or if the courts
conclude that EMF exposure harms individuals and that utilities are liable
for damages, then results of operations and financial condition could be
adversely affected, unless the costs can be recovered from customers.
Hazardous Material
By-products from the generation of electricity include materials such as
ash, slag, sludge, low level radioactive waste and spent nuclear fuel. In
addition, generating plants and transmission and distribution facilities have
used asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-
hazardous materials. Substantial costs to store and dispose of hazardous and
non-hazardous materials have been and will continue to be incurred.
Significant additional costs could be incurred to comply with new laws and
regulations if enacted and to clean up disposal sites under existing
legislation.
The Superfund created by the Comprehensive Environmental Response
Compensation and Liability Act addresses cleanup of hazardous substance
disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the cleanup programs. The Company has
been named by the Federal EPA as a "potentially responsible party" (PRP) for
seven sites and has received information requests for three other sites. For
two of the PRP sites, liability has been settled with little impact on
results of operations. I&M also has been named a PRP at one Illinois site
and has received an information request for one Indiana site under analogous
state cleanup laws. Although the potential liability associated with each
site must be evaluated individually, several general statements can be made
regarding such potential liability.
Whether the Company disposed of hazardous substances at a particular
site is often unsubstantiated; the quantity of material disposed of at a site
was generally small; and the nature of the material generally disposed of was
non-hazardous. Typically, the Company is one of many parties named PRPs for
a site and, although liability is joint and several, at least some of the
other parties are financially sound enterprises. Therefore, present
estimates do not anticipate material cleanup costs for identified disposal
sites. However, if for unknown reasons, significant costs are incurred for
cleanup, results of operations and possibly financial condition would be
adversely affected unless the costs can by recovered from insurance proceeds
and/or customers.
Nuclear Operating Cost
Operation and maintenance costs of the Company's two-unit 2,110 mw
Donald C. Cook Nuclear Plant are directly impacted by increasing Nuclear
Regulatory Commission requirements and increasing maintenance requirements
related to the aging of the units (Unit 1 began commercial operation in 1975
and Unit 2 in 1978). While nuclear fuel cost has declined, the estimated
cost to decommission the plant has increased to a range of $588 million to
$1.1 billion. The increase in the range from previous estimates is
attributable to uncertainty regarding future delays in the DOE's mandatory
Spent Nuclear Fuel (SNF) disposal program. Delays in finding a permanent
repository for SNF have increased costs reflecting a need to store SNF at the
plant site for an extended time after the plant ceases operations. Manage-
ment intends to continue to seek recovery of increasing decommissioning costs
over the remaining plant life. We continue to examine our operations for
better ways to operate and maintain our two nuclear units to control the
growth in operation, maintenance and decommissioning costs. Management
recently restructured its nuclear operations and staff to address these
concerns. Efforts are continuing to shorten refueling and maintenance
outages, to reduce their cost and to minimize the cost of replacement energy
during the outage periods. Should the nuclear units be retired early for
any reason or costs of maintaining, operating and decommissioning the
plant and disposing of its spent nuclear fuel not be recovered through
rates, results of operations and financial condition would be adversely
affected.
Litigation
The Company is involved in a number of legal proceedings and claims.
While we are unable to predict the outcome of such litigation, it is not
expected that the resolution of these matters will have a material adverse
effect on financial condition.
New Accounting Standards
Two new accounting standards were issued in 1993 that were adopted in
1994. The implementation of these new standards will not have a significant
effect on results of operations or financial condition.
Effects of Inflation
Inflation affects the cost of replacing utility plant and the cost of
operating and maintaining such plant. The rate-making process generally
limits recovery to the historical cost of assets resulting in economic losses
when inflation effects are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
INDEPENDENT AUDITORS' REPORT
To the Shareowners and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets of Indiana
Michigan Power Company and its subsidiaries as of December 31, 1993 and 1992,
and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Indiana Michigan Power Company
and its subsidiaries as of December 31, 1993 and 1992, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1993 in conformity with generally accepted
accounting principles.
As discussed in Notes 1 and 6 in Notes to Consolidated Financial Statements,
effective January 1, 1993, the Company changed its method of accounting for
income taxes to conform with Statement of Financial Accounting Standards No.
109 "Accounting for Income Taxes," and its method of accounting for
postretirement benefits other than pensions to conform with Statement of
Financial Accounting Standards No. 106 "Employers' Accounting for
Postretirement Benefits Other Than Pensions."
DELOITTE & TOUCHE
Columbus, Ohio
February 22, 1994
Consolidated Statements of Income
Year Ended December 31,
1993 1992 1991
(in thousands)
OPERATING REVENUES $1,202,643 $1,196,755 $1,225,867
OPERATING EXPENSES:
Fuel 220,206 193,830 251,325
Purchased Power 108,274 180,365 122,573
Other Operation 264,543 251,897 246,935
Maintenance 142,637 137,787 119,242
Depreciation and Amortization 138,794 133,365 132,285
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 15,644 16,303 16,961
Taxes Other Than Federal Income Taxes 67,918 62,189 62,783
Federal Income Taxes 34,707 25,499 46,474
Total Operating Expenses 992,723 1,001,235 998,578
OPERATING INCOME 209,920 195,520 227,289
NONOPERATING INCOME (LOSS) (234) 14,115 (3,721)
INCOME BEFORE INTEREST CHARGES 209,686 209,635 223,568
INTEREST CHARGES 80,373 85,687 86,636
NET INCOME 129,313 123,948 136,932
PREFERRED STOCK DIVIDEND REQUIREMENTS 14,225 15,417 15,417
EARNINGS APPLICABLE TO COMMON STOCK $ 115,088 $ 108,531 $ 121,515
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31,
1993 1992
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,602,527 $2,559,905
Transmission 839,198 829,507
Distribution 608,752 576,309
General (including nuclear fuel) 152,470 182,414
Construction Work in Progress 88,010 118,345
Total Electric Utility Plant 4,290,957 4,266,480
Accumulated Depreciation and Amortization 1,714,829 1,631,438
NET ELECTRIC UTILITY PLANT 2,576,128 2,635,042
OTHER PROPERTY AND INVESTMENTS 432,459 403,111
CURRENT ASSETS:
Cash and Cash Equivalents 3,752 7,459
Accounts Receivable:
Customers 67,246 62,325
Affiliated Companies 24,507 41,139
Miscellaneous 30,087 31,536
Allowance for Uncollectible Accounts (504) (562)
Fuel - at average cost 34,476 53,210
Materials and Supplies - at average cost 57,800 54,004
Accrued Utility Revenues 34,642 78,555
Prepayments 12,043 11,163
TOTAL CURRENT ASSETS 264,049 338,829
REGULATORY ASSETS:
Amounts Due From Customers For
Future Federal Income Taxes 286,948 -
Other 205,874 268,816
TOTAL REGULATORY ASSETS 492,822 268,816
TOTAL $3,765,458 $3,645,798
See Notes to Consolidated Financial Statements.
December 31,
1993 1992
(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 734,933 726,157
Retained Earnings 177,638 171,309
Total Common Shareowner's Equity 969,155 954,050
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 87,000 197,000
Subject to Mandatory Redemption 100,000 -
Long-term Debt 1,073,154 1,168,721
TOTAL CAPITALIZATION 2,229,309 2,319,771
OTHER NONCURRENT LIABILITIES 288,197 297,475
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 42,902
Short-term Debt - Commercial Paper 50,075 44,200
Accounts Payable:
General 40,437 37,214
Affiliated Companies 17,481 12,471
Taxes Accrued 54,473 15,829
Interest Accrued 18,894 22,759
Obligations Under Capital Leases 20,585 32,745
Other 79,367 71,891
TOTAL CURRENT LIABILITIES 281,312 280,011
DEFERRED FEDERAL INCOME TAXES 553,920 316,877
DEFERRED INVESTMENT TAX CREDITS 186,032 195,043
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 211,446 218,754
DEFERRED CREDITS 15,242 17,867
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $3,765,458 $3,645,798
Consolidated Statements of Cash Flows
Year Ended December 31,
1993 1992 1991
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 129,313 $ 123,948 $ 136,932
Adjustments for Noncash Items:
Depreciation and Amortization 148,270 141,453 141,813
Amortization of Rockport Plant
Unit 1 Phase-in Plan Deferrals 15,644 16,303 16,961
Amortization (Deferral) of Incremental
Nuclear Refueling Outage Expenses (net) 33,827 (47,200) -
Deferred Federal Income Taxes (49,905) 29,897 (21,877)
Deferred Investment Tax Credits (8,543) (9,673) (9,188)
Changes in Certain Current Assets and
Liabilities:
Accounts Receivable (net) 13,102 (7,432) (4,389)
Fuel, Materials and Supplies 14,938 1,018 (14,520)
Accrued Utility Revenues 43,913 (41,068) 3,816
Accounts Payable 8,233 (15,088) (15,222)
Taxes Accrued 38,644 4,514 9,937
Other (net) (17,064) (16,448) 4,446
Net Cash Flows From
Operating Activities 370,372 180,224 248,709
INVESTING ACTIVITIES:
Construction Expenditures (108,867) (125,908) (122,597)
Proceeds from Sales of Property
and Other 5,385 903 3,246
Net Cash Flows Used For
Investing Activities (103,482) (125,005) (119,351)
FINANCING ACTIVITIES:
Capital Contributions
from Parent Company 10,000 - -
Issuance of Cumulative
Preferred Stock 98,776 - -
Issuance of Long-term Debt 243,426 271,722 78,634
Retirement of Cumulative
Preferred Stock (112,300) - -
Retirement of Long-term Debt (392,093) (203,185) (92,623)
Change in Short-term Debt (net) 5,875 (6,750) 12,055
Dividends Paid on Common Stock (108,696) (106,465) (102,680)
Dividends Paid on Cumulative
Preferred Stock (15,585) (15,417) (15,417)
Net Cash Flows Used For
Financing Activities (270,597) (60,095) (120,031)
Net Increase (Decrease) in Cash and
Cash Equivalents (3,707) (4,876) 9,327
Cash and Cash Equivalents January 1 7,459 12,335 3,008
Cash and Cash Equivalents December 31 $ 3,752 $ 7,459 $ 12,335
See Notes to Consolidated Financial Statements.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1993 1992 1991
(in thousands)
Retained Earnings January 1 $171,309 $169,243 $150,408
Net Income 129,313 123,948 136,932
300,622 293,191 287,340
Deductions:
Cash Dividends Declared:
Common Stock 108,696 106,465 102,680
Cumulative Preferred Stock:
4-1/8% Series 495 495 495
4.56% Series 273 273 273
4.12% Series 165 165 165
5.90% Series 374 - -
6-1/4% Series 161 - -
6-7/8% Series 1,799 - -
7.08% Series 2,124 2,124 2,124
7.76% Series 2,716 2,716 2,716
8.68% Series 2,517 2,604 2,604
$2.15 Series 3,001 3,440 3,440
$2.25 Series 600 3,600 3,600
Total Cash Dividends Declared 122,921 121,882 118,097
Other 63 - -
Total Deductions 122,984 121,882 118,097
Retained Earnings December 31 $177,638 $171,309 $169,243
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,
transmission and distribution of electric power in northern and eastern
Indiana and a portion of southwestern Michigan. As a member of the American
Electric Power (AEP) System Power Pool (Power Pool) and a signatory company
to the AEP Transmission Equalization Agreement, its facilities are operated
in conjunction with the facilities of certain other AEP Co., Inc. owned
utilities as an integrated utility system.
The Company has two wholly-owned subsidiaries, Blackhawk Coal Company and
Price River Coal Company, that were formerly engaged in coal-mining
operations. Blackhawk Coal Company currently leases and subleases portions
of its Utah coal rights, land and related mining equipment to unaffiliated
companies. Price River Coal Company, which owns no land or mineral rights,
is inactive.
Regulation
As a member of the AEP System, I&M is subject to regulation by the Securi-
ties and Exchange Commission (SEC) under the Public Utility Holding Company
Act of 1935 (1935 Act). Retail rates are regulated by the Indiana Utility
Regulatory Commission (IURC) and the Michigan Public Service Commission
(MPSC). The Federal Energy Regulatory Commission (FERC) regulates wholesale
rates.
Principles of Consolidation
The consolidated financial statements include I&M and its wholly-owned
subsidiaries. Significant intercompany items were eliminated in consolida-
tion.
Basis of Accounting
As a 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) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS 71),
regulatory assets and liabilities are recorded to defer expenses or
revenues reflecting such rate-making differences.
Utility Plant
Electric utility plant is stated at original cost and is generally subject
to first mortgage liens. Additions, major replacements and betterments are
added to the plant accounts. Retirements from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation.
The costs of labor, materials and overheads incurred to operate and
maintain utility plant are included in operating expenses.
Allowance for Funds Used During Construction (AFUDC)
AFUDC is a noncash income item that is recovered over the service life of
utility plant through depreciation and represents the estimated cost of bor-
rowed and equity funds used to finance construction projects. The average
rates used to accrue AFUDC were 8.75% in 1993 and 9.25% in 1992 and 1991 and
the amounts of AFUDC accrued were $1.7 million, $3.8 million and $2.1 million
in 1993, 1992 and 1991, respectively.
Depreciation and Amortization
Depreciation 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 (i.e., production, transmission,
distribution, etc.). Amounts to be used for demolition of non-nuclear plant
are presently 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 3.
Rockport Plant
Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units. I&M
and AEP Generating Company (AEGCo), an affiliate, each owns 50% of one unit
(Rockport 1) and each leases a 50% interest in the other unit (Rockport 2)
from unaffiliated lessors under an operating lease. The gain on the sale and
leaseback of Rockport 2 was deferred and is being amortized, with related
taxes, over the initial lease term which expires in 2022.
Rate phase-in plans provide for the recovery and straight-line
amortization through 1997 of prior- year deferrals of Rockport 1 costs.
Deferred amounts under the phase-in plans were $59 million and $75 million at
December 31, 1993 and 1992, respectively.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with original
maturities of three months or less.
Operating Revenues
Revenues include an accrual for electricity consumed but unbilled at
month-end as well as billed revenues.
Fuel Costs
Fuel costs are matched with revenues in accordance with rate commission
orders. Revenues are accrued related to unrecovered fuel in both retail
jurisdictions and for replacement power costs in the Michigan jurisdiction
until approved for billing. Wholesale jurisdictional fuel cost changes are
expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs
Incremental operation and maintenance costs associated with refueling
outages at the Donald C. Cook Nuclear Plant (Cook Plant) are deferred with
the approval of regulators for amortization over the period (generally
eighteen months) beginning with the commencement of an outage until the
beginning of the next outage. Deferred amounts were $13.4 million and $47.2
million at December 31, 1993, and 1992, respectively.
Income Taxes
Effective January 1, 1993, the Company adopted the liability method of
accounting for income taxes as prescribed by SFAS 109, Accounting for Income
Taxes. Under this standard deferred federal income taxes are provided for
all temporary differences between the book cost and tax basis of assets and
liabilities which will result in a future tax consequence. In prior years
deferred federal income taxes were provided for timing differences between
book and taxable income except where flow-through accounting for certain
differences was reflected in rates. Flow-through accounting is a method
whereby federal income tax expense for a particular item is the same for
accounting and rate-making as in the federal income tax return. As a result
of the adoption of SFAS 109 significant additional deferred tax liabilities
were recorded for items afforded flow-through treatment in rates. In accor-
dance with SFAS 71 significant corresponding regulatory assets were also
recorded to reflect the future recovery of additional taxes due when the
temporary differences reverse. As a result of this change in accounting
effective January 1, 1993, deferred federal income tax liabilities increased
by $259.6 million and regulatory assets by $254.3 million, and net income was
reduced by $5.3 million.
Investment tax credits utilized in prior years' federal income tax returns
were deferred and are being amortized over the life of the related plant
investment in accordance with rate-making treatment.
Debt and Preferred Stock
Gains and losses on reacquired debt are deferred and amortized over the
term of the reacquired debt. If the debt is refinanced the reacquisition
costs are deferred and amortized over the term of the replacement debt.
Debt discount or premium and debt issuance expenses are amortized over the
term of the related debt, with the amortization included in interest charges.
Redemption premiums paid to reacquire preferred stock are deferred and
amortized in accordance with rate-making treatment. The excess of par value
over costs of preferred stock reacquired to meet sinking fund requirements is
credited to paid-in capital.
Other Property and Investments
Other property and investments are generally stated at cost.
Reclassifications
Certain prior-period amounts were reclassified to conform with current-
period presentation.
2. RATE MATTERS:
Rate Activity
In November 1993 the IURC granted a $34.7 million annual rate increase in
response to the Company's request for a $44.8 million increase filed in April
1992. The new rates include, among other things, recovery of the ongoing
amounts being accrued for postretirement benefits other than pensions (OPEB),
an increase in the provision for nuclear plant decommissioning costs and the
amortization of deferred incremental nuclear plant refueling outage costs.
In October 1993 the MPSC approved a settlement agreement that provides for
a three-step increase in recovery of nuclear decommissioning costs for the
Cook Plant. The first step increase of $1.2 million annually was effective
in November 1993. The second and third steps provide for recoveries to be
increased by $1 million annually in May 1994 and an additional $1 million
annually in November 1994. The MPSC also ordered that a new decommissioning
study be filed before December 1994.
Unaffiliated Coal and Affiliated Transportation Cost Recovery
In October 1993 the FERC denied a request by a wholesale customer seeking
rehearing of a February 1993 order. The February 1993 order reversed a 1990
administrative law judge's initial decision and dismissed the wholesale
customer's complaint concerning the reasonableness of coal costs from an
unaffiliated supplier who leased a Utah mining operation from the Company in
1986 and affiliated coal transportation charges. In December 1993 the
wholesale customer appealed the FERC order to the U.S. Court of Appeals.
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made although no new
generating capacity is expected to be constructed until the next century.
The aggregate construction program expenditures for 1994-1996 are estimated
to be $410 million and include the capital cost of compliance with the Clean
Air Act Amendments of 1990 (CAAA).
Long-term fuel supply contracts contain clauses for periodic adjustments.
The retail jurisdictions have fuel clause mechanisms that provide with the
regulators' review and approval for deferred recovery of changes in the cost
of fuel. The contracts are for various terms, the longest of which extend to
2014, and contain various clauses that would release the Company from its
obligation under certain force majeure conditions.
Unit Power Agreements
The Company is committed under unit power agreements to purchase 70% of
AEGCo's Rockport Plant capacity unless it is sold to unaffiliated utilities.
AEGCo has one long-term contract with an unaffiliated utility that expires in
1999 for 455 mw of Rockport Plant capacity.
The Company sells under contract up to 250 mw of Rockport Plant capacity
to Carolina Power and Light Company, an unaffiliated utility. The contract
expires in 2009.
Litigation
An appeal to the Indiana Court of Appeals by a local distribution utility
of a 1992 DeKalb County Circuit Court of Indiana decision is pending. The
circuit court dismissed the case filed under a provision of Indiana law that
allows the local distribution utility to seek damages equal to the gross
revenues received by the Company for rendering service in the designated
service territory of the local distribution utility. The Company had re-
ceived approximately $29 million in gross revenues from a major industrial
customer in the local distribution utility's service territory. The case
resulted from a Supreme Court of Indiana decision which overruled an appeals
court and voided an IURC order which assigned the major industrial customer
to the Company.
The Company is involved in other legal proceedings and claims. While
management is unable to predict the outcome of litigation, it is not expected
that the resolution of these other matters will have a material adverse
effect on financial condition.
Clean Air
The CAAA require significant reductions in sulfur dioxide and nitrogen
oxides emitted from various AEP System generating plants. The law estab-
lished a deadline of 1995 for the first phase of reductions in sulfur dioxide
emissions (Phase I) and the year 2000 for the second phase (Phase II) as well
as a permanent nationwide cap on sulfur dioxide emissions after 1999.
The AEP Systemwide compliance plan calls for fuel switching to medium-
sulfur coal at I&M's Tanners Creek Unit 4 with minimal capital cost. The
Breed unit which is a Phase I affected unit is scheduled to close on March
31, 1994. The Company's other generating units are not affected in Phase I.
The Company will incur additional costs to comply with Phase II
requirements at its generating plants. In addition, a portion of the costs
of compliance for the AEP System may be incurred through the Power Pool
(which is described in Note 5). If I&M is unable to recover compliance costs
from its customers, results of operations and financial condition would be
adversely impacted.
Other Environmental Matters
The Company and its subsidiaries are regulated by federal, state and local
authorities with respect to air and water quality and other environmental
matters.
The generation of electricity produces non-hazardous and hazardous by-
products. Asbestos, polychlorinated biphenyls (PCBs) and other hazardous
materials have been used in the generating plants and
transmission/distribution facilities. Substantial costs to store and dispose
of hazardous and non-hazardous materials have been incurred and will be
incurred. Significant additional costs could be incurred in the future to
meet the requirements of new laws and regulations, if enacted, and to clean
up disposal sites under existing legislation.
The Superfund created by the Comprehensive Environmental Response
Compensation and Liability Act addresses cleanup of hazardous substance
disposal sites and authorizes the United States Environmental Protection
Agency (Federal EPA) to administer the cleanup programs. The Company has
been named by the Federal EPA as a "potentially responsible party" (PRP) for
seven sites and has received information requests for three other sites. For
two of the PRP sites, liability has been settled with little impact on
results of operations. I&M also has been named a PRP at one Illinois site
and has received an information request for one Indiana site under analogous
state cleanup laws. Although the potential liability associated with each
site must be evaluated individually, several general statements can be made
regarding such potential liability.
Whether the Company disposed of hazardous substances at a particular site
is often unsubstantiated; the quantity of material disposed of at a site was
generally small; and the nature of the material generally disposed of was
non-hazardous. Typically, the Company is one of many parties named PRPs for
a site and, although liability is joint and several, at least some of the
other parties are generally financially sound enterprises. Therefore,
present estimates do not anticipate material cleanup costs for identified
disposal sites. However, if for unknown reasons, significant costs are
incurred for cleanup, results of operations and possibly financial condition
would be adversely affected unless the costs can by recovered from insurance
proceeds and/or customers.
Nuclear Plant
I&M owns and operates the two-unit 2,110 mw Cook Plant under licenses
granted by regulatory authorities. The operation of a nuclear facility
involves special risks, potential liabilities, and specific regulatory and
safety requirements. Should a nuclear incident occur at any facility in the
United States liability could be substantial. Should nuclear losses or
liabilities be underinsured or exceed accumulated funds, or should rate
recovery be denied, results of operations and financial condition would be
negatively affected. Specific information about risk management and
potential liabilities is discussed below.
Nuclear Insurance
Public liability is limited by law to $9.4 billion should an incident
occur at any licensed reactor in the United States. Commercially available
insurance provides $200 million of this coverage. In the event of a nuclear
incident at any nuclear plant in the United States the remainder of the
liability would be provided by a deferred premium assessment of $79.3 million
on each licensed reactor payable in annual installments of $10 million. As a
result, I&M could be assessed $158.6 million per nuclear incident payable in
annual installments of $20 million. The number of incidents for which
payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide $2.75 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 nuclear units. The Company could be assessed up to $24
million under these policies.
Spent Nuclear Fuel Disposal
Federal law provides for government responsibility for permanent spent
nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel
disposal. The 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 $148 million for fuel consumed prior to April 7,
1983 have been recorded as long-term debt and a regulatory asset. The
regulatory asset is being amortized as rate recovery occurs. I&M has not
paid the government the pre-April 1983 fees due to various factors including
continued delays and uncertainties related to the federal disposal program.
At December 31, 1993, funds collected from customers to dispose of nuclear
fuel and related earnings totalling $133 million were held in external funds
included in the financial statements as other property and investments.
Decommissioning
Decommissioning costs are accrued over the service life of the Cook Plant.
The licenses to operate the two nuclear units expire in 2014 and 2017. After
expiration of the licenses the plant is expected to be decommissioned through
dismantling. Estimated decommissioning costs range from $588 million to $1.1
billion in 1991 dollars. The wide range is caused by variables in the
estimated length of time spent nuclear fuel must be stored at the plant
subsequent to ceasing operations which depends on future developments in the
federal government's spent nuclear fuel disposal program. Decommissioning
costs are being recovered based on at least the lower end of the range in the
current and prior studies. I&M records decommissioning costs in other
operation expense and records a noncurrent decommissioning liability equal to
the rate recovery which was $13 million in 1993, $12 million in 1992 and $11
million in 1991. Decommissioning amounts recovered from customers are
deposited in external trusts. Trust fund earnings increase the fund assets
and the recorded liability. Trust fund earnings decrease the amount to be
recovered from ratepayers. At December 31, 1993, the decommissioning trust
fund balance and the accumulated provision for decommissioning were $170
million.
In recent rate increases, which are discussed in Note 2, the Company
received additional annual amounts for the decommissioning of the Cook Plant
of $10 million in its Indiana jurisdiction and $3.2 million phased-in in its
Michigan jurisdiction.
4. COMMON SHAREOWNER'S EQUITY:
Mortgage indentures, debentures, charter provisions and orders of
regulatory authorities place various restrictions on the use of retained
earnings for the payment of cash dividends on common stock. At December 31,
1993, $5.9 million of retained earnings were restricted. Regulatory approval
is required to pay dividends out of paid-in capital.
In 1993, I&M's parent made a cash capital contribution of $10 million.
Also in 1993 $1.2 million, representing the issuance costs for three series
of cumulative preferred stock, was charged to paid-in capital. There were no
other transactions affecting the common stock or paid-in capital accounts in
1993, 1992 or 1991.
5. RELATED PARTY TRANSACTIONS:
Benefits and costs of the System's generating plants are shared by members
of the Power Pool. Under the terms of the System Interconnection Agreement,
capacity charges and credits are designed to allocate the cost of the
System's capacity among the Power Pool members based on their relative peak
demands and generating reserves. Power Pool members are compensated for the
out-of-pocket costs of energy delivered to the Power Pool and charged for
energy received from the Power Pool.
Operating revenues include $204.6 million in 1993, $154.1 million in 1992
and $204.8 million in 1991 for supplying energy and capacity to the Power
Pool. Purchased power expense includes charges of $20.9 million in 1993,
$82.6 million in 1992 and $24.6 million in 1991 for energy received from the
Power Pool.
Power Pool members share in wholesale sales to unaffiliated utilities made
by the Power Pool. The Company's share was included in operating revenues in
the amount of $57 million in 1993, $45.8 million in 1992 and $65.5 million in
1991.
In addition, the Power Pool purchases power from unaffiliated companies
for immediate resale to other unaffiliated utilities. The Company's share of
these purchases was included in purchased power expense and totaled $5.1
million in 1993, $6.5 million in 1992 and $13.7 million in 1991. Revenues
from these transactions are included in the above Power Pool wholesale sales.
The cost of power purchased from AEGCo, an affiliated company that is not
a member of the Power Pool, was included in purchased power expense in the
amounts of $78.9 million, $88 million and $83 million in 1993, 1992 and 1991,
respectively.
The Company operates the Rockport Plant and bills AEGCo for its share of
operating costs.
AEP System companies participate in a transmission equalization agreement.
This agreement combines certain AEP System companies' investments in
transmission facilities and shares the costs of ownership in proportion to
the System companies' respective peak demands. Pursuant to the terms of the
agreement, credits of $47.4 million, $48.2 million and $46.2 million were
recorded in other operation expense for transmission services in 1993, 1992
and 1991, respectively.
Revenues from providing barging services were recorded in nonoperating
income as follows:
Year Ended December 31,
1993 1992 1991
(in thousands)
Affiliated Companies $25,372 $24,753 $23,863
Unaffiliated Companies 1,717 3,964 4,641
Total $27,089 $28,717 $28,504
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are determined by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the use
of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
6. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employees
meeting eligibility requirements. Benefits are based on service years and
compensation levels. Effective January 1, 1992 employees may retire without
reduction of benefits at age 62 and with reduced benefits as early as age 55.
Pension costs are allocated by first charging each System company with its
service cost and then allocating the remaining pension cost in proportion to
its share of the projected benefit obligation. The funding policy is to make
annual trust fund contributions equal to the net periodic pension cost up to
the maximum amount deductible for federal income taxes, but not less than the
minimum contribution required by law.
Net pension costs for the years ended December 31, 1993, 1992 and 1991
were $4.7 million, $5.6 million and $2.3 million, respectively.
An employee savings plan is offered which allows participants to
contribute up to 16% of their salaries into three investment alternatives,
including AEP Co., Inc. common stock. The Company contributes an amount
equal to one-half of the first 6% of the employees' contribution. The
Company's contribution is invested in AEP Co., Inc. common stock and totaled
$3.5 million in 1993, $3.3 million in 1992 and $3.1 million in 1991.
The AEP System provides certain other benefits for retired employees under
an AEP System other postretirement benefit plan. Substantially all employees
are eligible for health care and life insurance benefits if they have at
least 10 service years and, effective January 1, 1992, are age 55 at retire-
ment. Prior to 1993, net costs of these benefits were recognized as an
expense when paid and totaled $2.7 million and $2.6 million in 1992 and 1991,
respectively.
SFAS 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions, was adopted in January 1993. SFAS 106 requires the accrual of the
present value liability for the cost of postretirement benefits other than
pensions (OPEB) during the employee's service years. Prior service costs are
being recognized as a transition obligation over 20 years in accordance with
SFAS 106. OPEB costs are based on actuarially-determined stand alone costs
for each System company. The funding policy is to contribute incremental
amounts recovered through rates and cash generated by the corporate owned
life insurance (COLI) program. The annual accrued costs for 1993 required by
SFAS 106 for employees and retirees, which includes the recognition of one-
twentieth of the prior service transition obligation, was $12.4 million.
The Company received approval from the IURC to recover the increased OPEB
costs. In the Michigan and wholesale jurisdictions, the Company received
authority to defer the increased OPEB costs which are not being currently
recovered in rates. Future recovery of the deferrals and the annual ongoing
OPEB costs will be sought in the next base rate filings. At December 31,
1993, $6.2 million of incremental OPEB costs were deferred.
To reduce the impact of adopting SFAS 106, management took several
measures. First, a Voluntary Employees Beneficiary Association (VEBA) trust
fund for OPEB benefits was established. A $4.3 million advance contribution
was made to the trust fund in 1990, the maximum amount deductible for federal
income tax purposes. In 1993, a $700,000 contribution was made to the VEBA
trust fund from amounts recovered from ratepayers. In addition, to help fund
and reduce the future costs of OPEB benefits, a COLI program was implemented,
except where restricted by state law. The insurance policies have a
substantial cash surrender value which is recorded, net of equally
substantial policy loans, as other property and investments. The policies
generated cash of $600,000 in 1993, $1,700,000 in 1992 and $700,000 in 1991
inclusive of related tax benefits which was contributed to the VEBA trust
fund. In 1997 the premium will be fully paid and the cash generated by the
policies should increase significantly.
7. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1993 1992 1991
(in thousands)
Taxes other than federal
income taxes include:
Real and Personal
Property $35,683 $35,818 $33,265
State Gross Receipts,
Excise, Franchise
and Miscellaneous
State and Local 15,008 15,179 15,902
Payroll 9,001 8,911 8,075
State Income 8,226 2,281 5,541
Total $67,918 $62,189 $62,783
Cash was paid for:
Interest (net of
capitalized amounts) $82,509 $84,691 $84,581
Income Taxes 68,303 15,285 73,694
Noncash acquisitions
under capital
leases were 15,467 47,905 25,624
8. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1993 1992 1991
(in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 93,974 $ 9,122 $ 73,702
Deferred (50,959) 25,405 (18,793)
Deferred Investment Tax Credits (8,308) (9,028) (8,435)
Total 34,707 25,499 46,474
Charged (Credited) to
Nonoperating Income (net):
Current 6,026 1,569 3,348
Deferred 1,054 4,492 (3,084)
Deferred Investment Tax Credits (235) (645) (753)
Total 6,845 5,416 (489)
Total Federal Income Taxes as Reported $ 41,552 $30,915 $ 45,985
The following is a reconciliation of the difference between the amount of
federal income taxes computed by multiplying book income before federal
income taxes by the statutory tax rate, and the amount of federal income taxes
reported.
Year Ended December 31,
1993 1992 1991
(in thousands)
Net Income $129,313 $123,948 $136,932
Federal Income Taxes 41,552 30,915 45,985
Pre-tax Book Income $170,865 $154,863 $182,917
Federal Income Tax on Pre-tax Book
Income at Statutory Rate (35% in 1993
and 34% in 1992 and 1991) $59,803 $52,653 $62,192
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Removal Costs (2,632) (3,042) (2,259)
Adoption of SFAS 109 5,271 - -
Investment Tax Credits (net) (8,543) (9,011) (9,087)
Corporate Owned Life Insurance (4,697) (4,402) (3,044)
Other (7,650) (5,283) (1,817)
Total Federal Income Taxes as Reported $41,552 $30,915 $45,985
Effective Federal Income Tax Rate 24.3% 20.0% 25.1%
The following are the principal components of federal income taxes as
reported:
Year Ended December 31,
1993 1992 1991
(in thousands)
Current:
Federal Income Taxes $100,000 $10,029 $76,949
Investment Tax Credits - 662 101
Total Current Federal Income Taxes 100,000 10,691 77,050
Deferred:
Depreciation (12,167) (8,356) (6,969)
Unrecovered and Levelized Fuel (13,795) 11,729 (670)
Nuclear Fuel (3,271) 5,410 (6,484)
Deferred Return - Rockport Plant Unit 1 (2,644) (2,772) (2,864)
Deferred Net Gain - Rockport
Plant Unit 2 3,922 4,230 3,098
Levelized Nuclear Refueling Costs (11,488) 16,048 -
Accrued Interest Income (3,854) 3,854 -
Adoption of SFAS 109 5,271 - -
Other (11,879) (246) (7,988)
Total Deferred Federal Income Taxes (49,905) 29,897 (21,877)
Total Deferred Investment Tax Credits (8,543) (9,673) (9,188)
Total Federal Income Taxes as Reported $ 41,552 $30,915 $ 45,985
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliates in the AEP System. The
allocation of the AEP System's current consolidated federal income tax to the
System companies is in accordance with SEC rules under the 1935 Act. These
rules permit the allocation of the benefit of current tax losses and invest-
ment tax credits utilized to the System companies giving rise to them in
determining their current tax expense. The tax loss of the System parent
company, AEP Co., Inc., is allocated to its subsidiaries with taxable income.
With the exception of the loss of the parent company, the method of
allocation approximates a separate return result for each company in the
consolidated group.
The AEP System settled with the Internal Revenue Service (IRS) all issues
from the audits of the consolidated federal income tax returns for the years
prior to 1988. Returns for the years 1988 through 1990 are presently being
audited by the IRS. In the opinion of management, the final settlement of
open years will not have a material effect on results of operations.
The net deferred tax liability of $553.9 million at December 31, 1993 is
composed of deferred tax assets of $233.4 million and deferred tax
liabilities of $787.3 million. The significant temporary differences giving
rise to the net deferred tax liability are:
Deferred Tax Asset
(Liability)
(in thousands)
Property Related Temporary Differences $(494,966)
Amounts Due From Customers
For Future Federal Income Taxes (100,432)
Deferred Net Gain -
Rockport Plant Unit 2 62,761
All Other (net) (21,283)
Total Net Deferred Tax Liability $(553,920)
9. LEASES:
Leases of property, plant and equipment are for periods up to 35 years and
require payments of related property taxes, maintenance and operating costs.
The majority of the leases have purchase or renewal options and will be
renewed or replaced by other leases.
Lease rentals are generally charged to operating expense in accordance
with rate-making treatment. The components of rentals are as follows:
Year Ended December 31,
1993 1992 1991
(in thousands)
Operating Leases $103,884 $109,466 $101,013
Amortization of
Capital Leases 46,063 24,124 54,528
Interest on
Capital Leases 8,873 7,473 9,907
Total Rental
Payments $158,820 $141,063 $165,448
Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1993 1992
(in thousands)
Electric Utility Plant:
Production $ 8,033 $ 11,407
Distribution 14,717 14,702
General:
Nuclear Fuel
(net of amortization) 45,661 84,208
Other 48,418 46,494
Total Electric Utility
Plant 116,829 156,811
Accumulated Amortization 27,359 30,630
Net Electric Utility
Plant 89,470 126,181
Other Property 11,269 2,327
Accumulated Amortization 1,986 1,819
Net Other Property 9,283 508
Net Properties under
Capital Lease $ 98,753 $126,689
Obligations under
Capital Leases $ 98,753 $126,689
Less Portion Due Within
One Year 20,585 32,745
Noncurrent Liability $ 78,168 $ 93,944
Properties under operating leases and related obligations are not included
in the Consolidated Balance Sheets.
Future minimum lease rentals consisted of the following at December 31,
1993:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1994 $ 9,380 $ 98,667
1995 8,574 98,203
1996 7,601 97,885
1997 6,889 96,029
1998 6,257 91,118
Later Years 38,383 2,011,781
Total Future Minimum
Lease Payments 77,084(a) $2,493,683
Less Estimated
Interest Element 23,992
Estimated Present
Value of Future
Minimum Lease
Payments 53,092
Unamortized Nuclear
Fuel 45,661
Total $98,753
(a) Minimum lease rentals do not include nuclear fuel rentals. The rental
payments are based on the heat produced plus carrying
charges on the unamortized nuclear fuel balance.
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1993, 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 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. The Company issued
350,000 shares of 6.30% Cumulative Preferred Stock Subject to Mandatory
Redemption, par value $100, on February 8, 1994 and redeemed 350,000 shares
of 7.76% Cumulative Preferred Stock Not Subject to Mandatory Redemption, par
value $100, on February 14, 1994.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1993 Value Year Ended December 31, December 31, 1993 1993 1992
1993 1992 1991 (in thousands)
4-1/8% $106.125 $100 - - - 120,000 $ 12,000 $ 12,000
4.56% 102 100 - - - 60,000 6,000 6,000
4.12% 102.728 100 - - - 40,000 4,000 4,000
7.08% 101.85 100 - - - 300,000 30,000 30,000
7.76% 102.28 100 - - - 350,000 35,000 35,000
8.68% - - 300,000 - - - - 30,000
$2.15 - - 1,600,000 - - - - 40,000
$2.25 - - 1,600,000 - - - - 40,000
$ 87,000 $197,000
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Outstanding December 31,
Series(a) Value December 31, 1993 1993 1992
(in thousands)
5.90% (b) $100 400,000 $ 40,000 $ -
6-1/4%(c) 100 300,000 30,000 -
6-7/8%(d) 100 300,000 30,000 -
$100,000 $ -
(a) Not callable until after 2002. There are no aggregate sinking fund provisions through 2002.
(b) Shares issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund for the 5.90% cumulative
preferred stock will require the redemption of 20,000 shares each year and the redemption of the remaining shares outstanding on
January 1, 2009, in each case at $100 per share.
(c) Shares issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund for the 6-1/4%
cumulative preferred stock will require the redemption of 15,000 shares each year and the redemption of the remaining shares
outstanding on April 1, 2009, in each case at $100 per share.
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1993 1992
(in thousands)
First Mortgage Bonds $ 571,468 $ 713,916
Installment Purchase
Contracts 307,823 308,333
Other Long-term Debt (a) 147,810 143,321
Notes Payable to Banks 40,000 40,000
Sinking Fund Debentures 6,053 6,053
1,073,154 1,211,623
Less Portion Due Within
One Year - 42,902
Total $1,073,154 $1,168,721
(a) Nuclear Fuel Disposal Costs including interest accrued. See Note 3.
First mortgage bonds outstanding were as follows:
December 31,
1993 1992
(in thousands)
% Rate Due
4-3/8 1993 - August 1 $ - $ 42,902
7-7/8 1997 - February 1 - 50,000
9-1/8 1997 - July 1 - 75,000
7 1998 - May 1 35,000 35,000
7.30 1999 - December 15 35,000 35,000
8-7/8 2000 - April 1 - 50,000
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 -
8-3/8 2003 - December 1 - 40,000
9-1/2 2008 - March 1 - 34,034
8-3/4 2017 - February 1 100,000 100,000
9.50 2021 - May 1 10,000 10,000
9.50 2021 - May 1 10,000 10,000
9.50 2021 - May 1 20,000 20,000
8.75 2022 - May 1 50,000 50,000
8.50 2022 - December 15 75,000 75,000
7.80 2023 - July 1 20,000 -
7.35 2023 - October 1 20,000 -
7.20 2024 - February 1 40,000 -
Unamortized Discount (net) (3,532) (3,020)
571,468 713,916
Less Portion Due Within One Year - 42,902
Total $571,468 $671,014
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,
1993 1992
(in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7 2006 - May 1 $ - $ 40,000
6-7/8 2006 - May 1 - 12,000
7 2015 - April 1 25,000 25,000
5.9 2019 - November 1 52,000 -
City of Rockport, Indiana:
9-1/4 2014 - August 1 50,000 50,000
6-3/4(a)2014 - August 1 50,000 50,000
(b) 2014 - August 1 50,000 50,000
7.6 2016 - March 1 40,000 40,000
City of Sullivan, Indiana:
7-3/8 2004 - May 1 - 7,000
6-7/8 2006 - May 1 - 25,000
7-1/2 2009 - May 1 - 13,000
5.95 2009 - May 1 45,000 -
Unamortized Discount (4,177) (3,667)
Total $307,823 $308,333
(a) The adjustable interest rate changed on August 1, 1990 and will change
every five years thereafter.
(b) The variable interest rate is determined weekly. The average weighted
interest was 3.0% in 1993 and 3.7% for 1992.
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 certain series
the principal is payable at stated maturities or on the demand of the bond-
holders at periodic interest adjustment dates. Accordingly, the installment
purchase contracts have been classified for repayment purposes based on their
next interest rate adjustment date. Certain series are supported by bank
letters of credit which expire in 1995.
A $40 million unsecured promissory note payable to a bank is due November
19, 1995 at an annual interest rate of 9.07%.
The sinking fund debentures are due May 1, 1998 at an interest rate of 7-
1/4%. Prior to December 31, 1993, sufficient principal amounts of debentures
had been reacquired in anticipation of all future sinking fund requirements.
Additional debentures of up to $300,000 may be called annually.
At December 31, 1993, annual long-term debt payments, excluding premium or
discount, are as follows:
Principal Amount
(in thousands)
1994 $ -
1995 140,000
1996 -
1997 -
1998 41,053
Later Years 899,810
Total $1,080,863
Short-term debt borrowings are limited by provisions of the 1935 Act to
$200 million and further limited by charter provisions to $127 million.
Lines of credit are shared with AEP System companies and at December 31, 1993
and 1992 were available in the amounts of $537 million and $521 million,
respectively. Commitment fees of approximately 3/16 of 1% a year are paid to
the banks to maintain the lines of credit.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS:
The carrying amounts of cash and cash equivalents, accounts receivable,
short-term debt, and accounts payable approximate fair value because of the
short-term maturity of these instruments. At December 31, 1993 and 1992
fair values for external trust funds were $321 million and $270 million and
carrying values were $303 million and $262 million, respectively. Fair
values for long-term debt were $1.1 billion and $1.2 billion at December 31,
1993 and 1992, respectively. Fair value at December 31, 1993 for preferred
stocks subject to mandatory redemption, which were issued in 1993, was $99
million. Fair values are based on quoted market prices for the same or
similar issues and the current dividend or interest rates offered for
instruments of the same remaining maturities. External trust funds are used
to accumulate funds collected from customers for future nuclear liabilities
and are reported on the balance sheet as other property and investments. The
carrying amount of the pre-April 1983 spent nuclear fuel disposal liability
approximates the Company's best estimate of its fair value.
13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods
Ended Operating Operating Net
Revenues Income Income
(in thousands)
1993
March 31 $302,968 $53,269 $28,522
June 30 278,100 40,722 21,397
September 30 320,409 52,898 33,658
December 31 301,166 63,031 45,736
1992
March 31 301,134 54,022 35,035
June 30 280,421 43,535 24,844
September 30 311,080 45,323 24,384
December 31 304,120 52,640 39,685
Fourth quarter 1992 net income includes $13 million comprised of interest
on prior years' federal income tax refunds and cost reductions due to
favorable benefit plans experience.