Selected Consolidated Financial Data
Year Ended December 31,
1995 1994 1993 1992 1991
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,283,157 $1,251,309 $1,202,643 $1,196,755 $1,225,867
Operating Expenses 1,077,434 1,029,340 992,485 1,000,967 998,339
Operating Income 205,723 221,969 210,158 195,788 227,528
Nonoperating Income (Loss) 6,272 7,428 (234) 14,115 (3,721)
Income Before Interest Charges 211,995 229,397 209,924 209,903 223,807
Interest Charges 70,903 71,895 80,580 85,920 86,844
Net Income 141,092 157,502 129,344 123,983 136,963
Preferred Stock Dividend Requirements 11,791 11,681 14,256 15,452 15,448
Earnings Applicable to Common Stock $ 129,301 $ 145,821 $ 115,088 $ 108,531 $ 121,515
December 31,
1995 1994 1993 1992 1991
BALANCE SHEETS DATA: (in thousands)
Electric Utility Plant $4,319,564 $4,269,306 $4,290,957 $4,266,480 $4,135,820
Accumulated Depreciation and
Amortization 1,751,965 1,659,940 1,714,829 1,631,438 1,521,349
Net Electric Utility Plant $2,567,599 $2,609,366 $2,576,128 $2,635,042 $2,614,471
Total Assets $3,928,337 $3,878,035 $3,723,648 $3,608,645 $3,442,606
Common Stock and Paid-in Capital $ 787,686 $ 790,234 $ 790,625 $ 781,818 $ 781,783
Retained Earnings 235,107 216,658 177,638 171,309 169,243
Total Common Shareholder's Equity $1,022,793 $1,006,892 $ 968,263 $ 953,127 $ 951,026
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption $ 52,000 $ 52,000 $ 87,000 $ 197,000 $ 197,000
Subject to Mandatory Redemption (a) 135,000 135,000 100,000 - -
Total Cumulative Preferred Stock $ 187,000 $ 187,000 $ 187,000 $ 197,000 $ 197,000
Long-term Debt (a) $1,040,101 $1,069,887 $1,073,154 $1,211,623 $1,130,709
Obligations Under Capital Leases (a) $ 142,506 $ 152,589 $ 98,753 $ 126,689 $ 102,985
Total Capitalization and Liabilities $3,928,337 $3,878,035 $3,723,648 $3,608,645 $3,442,606
(a) Including portion due within one year.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Business Outlook
Since its enactment in 1992, the Energy Policy Act has fostered
competition in the generation and sale of electricity in the wholesale
market. The prospect for market driven rates is powering a movement,
mainly among large industrial energy users, to introduce competition to the
retail market as well. As a result management expects that competition
will be a significant factor influencing the Company s future results of
operations. Among the other factors that could impact future earnings are
nuclear fuel disposal costs and nuclear decommissioning costs.
A significant expansion of competition in the generation and sale of
electricity could result in an adverse effect on future results of
operations from stranded costs and the write-off of regulatory assets.
Stranded costs occur when a customer switches to a new supplier creating
the issue of who pays for investments and commitments that are no longer
needed, economical or recoverable in a competitive market. The amount of
any losses the Company may experience from stranded costs depends on the
extent to which direct competition is introduced to the Company s business
and the market price of energy. Cost-based regulation traditionally
results in the recognition of revenues and expenses in accordance with rate
commission orders which can result in revenue and expense recognition in
different time periods than for enterprises that are not regulated. As a
result, regulatory assets have been recorded by regulated utility companies
representing the deferral of costs for recovery in future periods. At
December 31, 1995, the Company had $459 million of regulatory assets. In
order to maintain regulatory assets, the Company s rates must be cost-based
regulated. Management has reviewed the evidence currently available and
concluded that the Company continues to meet the requirements to apply
rate-regulated accounting standards. In the event a portion of the
Company s business no longer met these requirements, regulatory assets
would have to be written off for that portion of the business.
Whether future results of operations are adversely affected by losses or
write-offs will also depend on whether and how equitable recovery is
provided for by the applicable regulators. We intend to seek appropriate
recovery of any stranded costs and regulatory assets that may result from a
transition to competition.
The Company, as a member of the AEP System, has the financial strength,
geographic reach, location and cost structure to be an able competitor.
Although no assurance can be given that the Company can maintain this
position in the future, management is taking steps to prepare for the
challenges that increased competition will present. In 1995 management
took steps to prepare for competition by realigning the Company s
operations, along with the operations of the AEP System s other operating
companies, into functional operating units, expanding marketing and
customer service efforts and proposing a plan for an orderly transition to
retail competition. Management also proposed and filed open access
transmission rates.
The realignment from separate operating company organizations to distinct
fossil-fired and hydroelectric generation, nuclear generation and energy
delivery operating units will facilitate the unbundling of electric
services to separate competitive generation services from regulated
transmission and distribution services. It also should facilitate our
ability to more efficiently and effectively meet customer needs. Process
improvement and cost control will be key performance objectives for our new
operating units.
In October of 1995 management proposed the creation of an Independent
System Operator to operate a multi-state transmission grid to facilitate
equal, safe and efficient transmission. Management also proposed the
eventual creation of a Regional Power Exchange that would accept offers to
buy and sell power and would settle transactions based on the price at
which supply and demand are balanced. Under the proposal regulators would
continue to regulate delivery services and provide for the recovery of any
stranded costs and regulatory assets through a usage charge.
Management has also offered access to AEP s extensive transmission grid
at 142 interconnections to all parties under the same terms and conditions
available to the AEP System. This should provide the Company with greater
opportunities for transmission service revenues. Management has also
responded to our retail customers needs by introducing new cost-based
regulated rate designs (interruptible buy-through and real time pricing).
These proposals were issued to enable the Company to participate in a
meaningful way in the process of shaping the form of the future competitive
playing field. Our success will depend on our ability to obtain a level
playing field, improve and expand on our energy sales and services and
maintain and improve on our relatively low cost structure.
Nuclear Cost
The Company s nuclear plant, the Donald C. Cook Nuclear Plant, has
recently achieved a superior rating from the Institute of Nuclear Power
Operations, a nuclear industry oversight group, and received improved
Nuclear Regulatory Commission (NRC) performance ratings. In an effort to
continue to reduce costs and enhance organizational efficiency, management
announced in November that during the summer of 1996 we will consolidate
our Columbus-based nuclear engineering, management and support staff with
the plant staff at or near the Cook Plant in Bridgman, Michigan.
The cost to operate and maintain the two-unit Cook Plant
is impacted by federal laws and NRC requirements. The Nuclear Waste
Policy Act of 1982 established federal responsibility for the permanent
off-site disposal of spent nuclear fuel and high-level radioactive waste.
By law the Company participates in the Department of Energy s (DOE s) Spent
Nuclear Fuel (SNF) disposal program which is described in Note 3 of the
Notes to Consolidated Financial Statements. Since 1983 our consumers of
nuclear generated electricity have paid $237 million for the future
disposal, at a yet to be built DOE disposal facility, of spent nuclear fuel
consumed at the Cook Plant. 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. The federal government has
not made sufficient progress toward the selection of a site and
construction of a permanent repository and as long as there is a delay in
establishing the permanent storage repository for spent nuclear fuel, the
cost of a temporary or permanent repository will continue to increase.
The cost to decommission the Cook Plant is affected by NRC regulations
and the DOE s SNF disposal program. Studies completed in 1994 estimate the
cost to decommission the plant and dispose of low-level nuclear waste
accumulation to range from $634 million to $988 million in 1993 dollars.
The decommissioning estimate could escalate due to uncertainty in the DOE s
SNF disposal program and the length of time that SNF may need to be stored
at the plant site delaying decommissioning. Decommissioning costs are
being recovered in the 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. However, future results of operations
and possibly financial condition could be adversely affected if the costs
of spent nuclear fuel disposal and decommissioning continue to increase and
if for some reason such costs cannot be recovered.
Environmental Concerns
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, the generating plants and transmission and distribution
facilities have used asbestos, polychlorinated biphenyls (PCBs) and other
hazardous and non-hazardous materials. The Company is currently incurring
costs to safely store and dispose of such substances, and additional costs
could be incurred to comply with new laws and regulations if enacted.
The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA or Superfund legislation) addresses clean-up of hazardous
substances at disposal sites and authorizes the United States
Environmental Protection Agency (Federal EPA) to administer the clean-up
programs. As of year-end 1995, I&M is currently involved in litigation
with respect to two sites being overseen by the Federal EPA and has been
named by the Federal EPA as a Potentially Responsible Party (PRP) for three
other sites. Information requests have been received for four additional
sites which could lead to PRP designation. I&M also has received information
requests with respect to two sites administered by state authorities.
Liability has been resolved for a number of sites with no significant effect
on results of operations. The Company's present estimates do not anticipate
material cleanup costs for identified sites for which I&M has been declared a
PRP. However, if for reasons not currently identified significant costs are
required for cleanup, future results of operations and possibly financial
condition would be adversely affected unless the costs can be recovered.
Litigation
The Company is involved in a number of legal proceedings and claims.
While management is 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 the results of operations and/or financial condition.
Results of Operations
Net Income
Although revenues increased 2.5% in 1995, net income declined 10.4% to
$141 million mainly due to increased operating expenses, including the
unfavorable effect of a provision for severance benefits in connection with
the realignment of operations and increased federal income tax expense. The
increase in net income in 1994 of 21.8% was the result of a retail base
rate increase in the Indiana jurisdiction, reduced interest expense due to
the retirement of long-term debt, the effect of adopting Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS
109) in 1993 and the retirement in 1994 of a generating plant.
Operating Revenues and Energy Sales Increase
Operating revenues increased 2.5% in 1995 following a 4% increase in
1994. The changes in revenues are analyzed as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) 1995 1994
Amount % Amount %
Retail:
Price Variance $ (0.7) $ 69.8
Volume Variance 29.9 30.5
29.2 3.3 100.3 12.9
Wholesale:
Power Pool:
Price Variance (7.9) (3.8)
Volume Variance 39.4 (62.4)
Capacity Charges (28.3) 2.1
3.2 (64.1)
Unaffiliated Utilities:
Price Variance (12.7) 21.1
Volume Variance 14.0 (9.0)
1.3 12.1
Total Wholesale 4.5 1.3 (52.0)(12.8)
Other Operating Revenues (1.9) 0.4
Total $ 31.8 2.5 $ 48.7 4.0
The increase in 1995 operating revenues resulted from increased energy
usage by retail and unaffiliated wholesale customers. Retail energy sales
increased 3% reflecting warmer summer weather in 1995 and a colder fourth
quarter in 1995 than 1994 and continuing growth in the number of
residential, commercial and industrial customers. While wholesale energy
sales increased 34%, wholesale revenues increased only 1% in 1995. The
substantial increase in wholesale energy sales was primarily due to a 69%
increase in energy sales to the AEP System Power Pool (Power Pool), which
are made at cost, reflecting the increased availability of lower cost
nuclear generating capacity in 1995. During 1995 one nuclear generating
unit was out of service for refueling while both units were refueled in
1994. Also contributing to the wholesale energy sales increase were
increased sales to unaffiliated entities. Sales to the Company s municipal
and cooperative customers and to unaffiliated utilities by the Power Pool
which are shared by the Company increased primarily due to
the warmer summer and the colder fourth quarter weather in 1995 as compared
to 1994. The increase in wholesale sales did not lead to a corresponding
increase in revenues due to reduced capacity credits from the Power Pool
and increasing competition in the wholesale energy market. Capacity
credits are designed to allocate the cost of the AEP System s generating
capacity among the members of the Power Pool based on their relative peak
demands and generating reserves. An increase in the Company s peak demand
during 1995 relative to the peak demand of all Power Pool members caused
the decrease in capacity revenues.
In 1994 revenues rose 4% largely due to increased retail revenues partly
offset by a decline in total wholesale revenues. The growth in retail
revenues resulted from a $34.7 million annual base rate increase in the
Indiana jurisdiction, increased decommissioning expense recoveries in the
Michigan jurisdiction and a 4% increase in energy sales due to growth in
the number of retail customers. The decline in 1994 wholesale revenues
reflected the decrease in energy available for delivery to the Power Pool
due to the scheduled refueling and maintenance outages at the Company s two
nuclear units in 1994 and lower energy sales by the Power Pool due to mild
weather throughout most of 1994. While severe weather in January 1994 and
hot June weather increased the Power Pool s short-term wholesale sales in
those months, the mild weather throughout the remainder of 1994, combined
with increased competition in the wholesale market reduced short-term sales
for the year.
Operating Expenses Increase
Total operating expenses increased 5% in 1995 or $48 million reflecting
the increased operation of the Company s nuclear units and severance pay
accruals. In 1994 total operating expenses rose 4% or $37 million largely
due to increased accruals for nuclear decommissioning expense and employee
benefits. The significant changes in operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions) 1995 1994
Amount % Amount %
Fuel $21.2 10.5 $(18.5) (8.4)
Purchased Power (5.8) (4.4) 23.0 21.2
Other Operation 10.3 3.5 28.5 10.6
Federal Income Taxes 15.7 40.9 6.4 19.9
Fuel expense increased substantially in 1995 due to a 51% increase in
nuclear generation reflecting the increased availability of nuclear
generating capacity. During 1995 one unit was out of service for refueling
while both units were out of service for refueling in 1994. Fuel expense
declined in 1994 due to a significant reduction (43%) in nuclear generation
reflecting the refueling outages partially offset by a 6% increase in
fossil generation.
The increase in purchased power expense in 1994 reflects increased
receipts from the Power Pool due to the nuclear outages and increased
purchases from unaffiliated utilities for immediate resale to other
unaffiliated utilities.
Other operation expense increased in 1995 primarily due to a provision
for severance pay related to the functional realignment of operations and
costs related to the development of a new activity based budgeting system.
The 1994 increase was caused by regulatory-approved increases in nuclear
decommissioning accruals, accruals for other postretirement benefits
commensurate with rate recovery and expenses related to the closing of the
Company s Breed Plant.
The increase in federal income taxes attributable to operations in 1995
was primarily due to changes in certain book/tax differences accounted for
on a flow-through basis and the effects of favorable accrual adjustments
recorded in 1994 in connection with the resolution of the audit of prior
years tax returns. Federal income taxes attributable to operations
increased in 1994 due to increased pre-tax operating income.
Nonoperating Income and Financing Costs
Nonoperating income increased in 1994 reflecting a favorable tax effect
from the Breed Plant closing and the unfavorable effect in 1993 of adopting
SFAS 109 for nonutility assets and liabilities.
Interest charges declined in 1994 due to debt repayments and a
refinancing program which lowered interest rates. In 1994, $10 million of
long-term bonds were retired and $90 million were refinanced. The full
year effects from 1993 refinancings and retirements also contributed to the
1994 reduction.
Construction Spending
Gross plant and property additions were $151 million in 1995 and $212
million in 1994. Management estimates construction expenditures for the
next three years to be $315 million with no major new generating plant
construction planned. The funds for construction of new facilities and im-
provement of existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred stock
issuances and investments in common equity by the Company's parent, Ameri-
can Electric Power Co., Inc. However, all of the construction expenditures
for the next three years are expected to be financed internally.
Liquidity and Capital Resources
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, 1995, $372 million of unused short-term
lines of credit shared with other AEP System companies were available. An
authorization by the Securities and Exchange Commission limits short-term
borrowings to $175 million. Periodic reductions of outstanding short-term
debt are made through issuances of long-term debt and preferred stock and
through additional capital contributions by the parent company.
The Company has regulatory approval to issue up to $150 million of long-
term debt. Management expects to use the proceeds of future long-term
financings to retire short-term debt, refinance maturing and other long-
term debt, refund cumulative preferred stock and fund construction
expenditures.
The Company presently exceeds all minimum coverage requirements for
issuance of mortgage bonds and preferred stock. The minimum coverage
ratios are 2.0 for mortgage bonds and 1.5 for preferred stock. At December
31, 1995, the mortgage bonds and preferred stock coverage ratios were 6.25
and 2.63, respectively.
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.
New Accounting Rules
The Financial Accounting Standards Board (FASB) issued a new accounting
standard, SFAS 121 Accounting for Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of. The new standard is effective
beginning with 1996 accounting periods. The initial implementation of this
new standard is not expected to have a significant impact on the Company.
In 1996 the FASB issued an exposure draft Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets. This
document proposes that the present value of any decommissioning or other
closure or removal obligation be recorded as a liability when the
obligation is incurred. A corresponding asset would be recorded in the
plant investment account and recovered through depreciation charges over
the asset s life. A proposed transition rule would require that an entity
report in income the cumulative effect of initially applying the new
standard. The Company is currently studying the impact of the proposed
rules and evaluating its potential impact.
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, 1995 and
1994, and the related consolidated statements of income, retained earnings,
and cash flows for each of the three years in the period ended December 31,
1995. 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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 1995 in conformity with generally
accepted accounting principles.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 27, 1996
Consolidated Statements of Income
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING REVENUES $1,283,157 $1,251,309 $1,202,643
OPERATING EXPENSES:
Fuel 222,967 201,739 220,206
Purchased Power 125,413 131,234 108,274
Other Operation 306,967 296,625 268,144
Maintenance 141,813 139,423 142,637
Depreciation and Amortization 138,814 136,244 138,794
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 15,644 15,644 15,644
Taxes Other Than Federal Income Taxes 71,791 70,078 66,805
Federal Income Taxes 54,025 38,353 31,981
Total Operating Expenses 1,077,434 1,029,340 992,485
OPERATING INCOME 205,723 221,969 210,158
NONOPERATING INCOME (LOSS) 6,272 7,428 (234)
INCOME BEFORE INTEREST CHARGES 211,995 229,397 209,924
INTEREST CHARGES 70,903 71,895 80,580
NET INCOME 141,092 157,502 129,344
PREFERRED STOCK DIVIDEND REQUIREMENTS 11,791 11,681 14,256
EARNINGS APPLICABLE TO COMMON STOCK $ 129,301 $ 145,821 $ 115,088
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31,
1995 1994
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,507,667 $2,494,834
Transmission 867,541 849,920
Distribution 666,810 644,720
General (including nuclear fuel) 186,959 204,909
Construction Work in Progress 90,587 74,923
Total Electric Utility Plant 4,319,564 4,269,306
Accumulated Depreciation and Amortization 1,751,965 1,659,940
NET ELECTRIC UTILITY PLANT 2,567,599 2,609,366
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 433,619 353,469
OTHER PROPERTY AND INVESTMENTS 150,994 127,424
CURRENT ASSETS:
Cash and Cash Equivalents 13,723 9,907
Accounts Receivable:
Customers 82,434 74,491
Affiliated Companies 21,881 24,848
Miscellaneous 11,450 20,334
Allowance for Uncollectible Accounts (334) (121)
Fuel - at average cost 29,093 35,802
Materials and Supplies - at average cost 72,861 59,897
Accrued Utility Revenues 43,937 40,582
Prepayments 10,191 8,414
TOTAL CURRENT ASSETS 285,236 274,154
REGULATORY ASSETS 458,525 482,107
DEFERRED CHARGES 32,364 31,515
TOTAL $3,928,337 $3,878,035
See Notes to Consolidated Financial Statements.
December 31,
1995 1994
(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 731,102 733,650
Retained Earnings 235,107 216,658
Total Common Shareholder's Equity 1,022,793 1,006,892
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 52,000 52,000
Subject to Mandatory Redemption 135,000 135,000
Long-term Debt 1,034,048 929,887
TOTAL CAPITALIZATION 2,243,841 2,123,779
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 269,392 211,963
Other 184,103 192,758
TOTAL OTHER NONCURRENT LIABILITIES 453,495 404,721
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 6,053 140,000
Short-term Debt 89,975 50,600
Accounts Payable - General 37,744 40,417
Accounts Payable - Affiliated Companies 22,962 22,720
Taxes Accrued 71,696 63,621
Interest Accrued 16,158 19,436
Obligations Under Capital Leases 31,776 39,003
Other 74,463 65,409
TOTAL CURRENT LIABILITIES 350,827 441,206
DEFERRED INCOME TAXES 612,147 634,902
DEFERRED INVESTMENT TAX CREDITS 155,202 164,206
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 99,832 103,539
DEFERRED CREDITS 12,993 5,682
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $3,928,337 $3,878,035
Consolidated Statements of Cash Flows
Year Ended December 31,
1995 1994 1993
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 141,092 $ 157,502 $ 129,344
Adjustments for Noncash Items:
Depreciation and Amortization 148,441 146,966 148,270
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 15,644 15,644 15,644
Amortization (Deferral) of Incremental Nuclear
Refueling Outage Expenses (net) 8,684 (18,779) 33,827
Deferred Federal Income Taxes (23,564) (19,775) (52,631)
Deferred Investment Tax Credits (9,004) (13,877) (8,543)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 4,121 (7,200) 14,441
Fuel, Materials and Supplies (6,255) (3,423) 14,938
Accrued Utility Revenues (3,355) (5,940) 43,913
Accounts Payable (2,431) 5,219 8,233
Taxes Accrued 8,075 9,148 38,644
Other (net) (23,099) (12,145) (15,708)
Net Cash Flows From Operating Activities 258,349 253,340 370,372
INVESTING ACTIVITIES:
Construction Expenditures (117,785) (118,094) (108,867)
Long-term Receivable from Customer
for Construction of Facilities (18,733) - -
Proceeds from Sales of Property and Other 9,325 2,038 5,385
Net Cash Flows Used For Investing Activities (127,193) (116,056) (103,482)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - - 10,000
Issuance of Cumulative Preferred Stock - 34,618 98,776
Issuance of Long-term Debt 96,819 89,221 243,426
Retirement of Cumulative Preferred Stock - (35,798) (112,300)
Retirement of Long-term Debt (141,122) (101,833) (392,093)
Change in Short-term Debt (net) 39,375 525 5,875
Dividends Paid on Common Stock (110,852) (106,608) (108,696)
Dividends Paid on Cumulative Preferred Stock (11,560) (11,254) (15,585)
Net Cash Flows Used For Financing Activities (127,340) (131,129) (270,597)
Net Increase (Decrease) in Cash and
Cash Equivalents 3,816 6,155 (3,707)
Cash and Cash Equivalents January 1 9,907 3,752 7,459
Cash and Cash Equivalents December 31 $ 13,723 $ 9,907 $ 3,752
See Notes to Consolidated Financial Statements.
Consolidated Statements of Retained Earnings
Year Ended December 31,
1995 1994 1993
(in thousands)
Retained Earnings January 1 $216,658 $177,638 $171,309
Net Income 141,092 157,502 129,344
357,750 335,140 300,653
Deductions:
Cash Dividends Declared:
Common Stock 110,852 106,608 108,696
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 2,360 2,360 374
6-1/4% Series 1,875 1,875 161
6.30% Series 2,205 1,978 -
6-7/8% Series 2,063 2,063 1,799
7.08% Series 2,124 2,124 2,124
7.76% Series - 317 2,716
8.68% Series - - 2,517
$2.15 Series - - 3,001
$2.25 Series - - 600
Total Cash Dividends Declared 122,412 118,258 122,921
Capital Stock Expense 231 224 94
Total Deductions 122,643 118,482 123,015
Retained Earnings December 31 $235,107 $216,658 $177,638
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 to 537,000 retail
customers in northern and eastern Indiana and a portion of southwestern
Michigan. Wholesale electric power is supplied to neighboring utility
systems. 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 affiliated utilities as an integrated
utility system.
The Company has two wholly-owned subsidiaries, which are consolidated in
these financial statements, 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 subsidiary of AEP Co., Inc., I&M is subject to regulation by the
Securities and Exchange Commission (SEC) under the Public Utility Holding
Company Act of 1935 (1935 Act). Retail rates are regulated by the Indiana
Utility Regulatory Commission (IURC) and the Michigan Public Service Com-
mission. The Federal Energy Regulatory Commission (FERC) regulates
wholesale rates.
Principles of Consolidation
The consolidated financial statements include I&M and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consolida-
tion.
Basis of Accounting
As a cost-based rate-regulated entity, I&M's financial statements
reflect the actions of regulators that result in the recognition of
revenues and expenses in different time periods than enterprises that are
not cost-based rate regulated. In accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain
Types of Regulation, regulatory assets and liabilities are recorded to
reflect the economic effects of regulation.
Use of Estimates
The preparation of these financial statements in conformity with generally
accepted accounting principles requires in certain instances the use of
management s 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 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 nonoperating income item that is recovered with
regulator approval over the service life of utility plant through depreci-
ation and represents the estimated cost of borrowed and equity funds used
to finance construction projects. The amounts of AFUDC for 1995, 1994 and
1993 were not significant.
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 as follows:
Functional Class Composite
of Property Annual Rates
Production:
Steam-Nuclear 3.4%
Steam-Fossil-Fired 4.4%
Hydroelectric-Conventional 3.2%
Transmission 1.9%
Distribution 4.2%
General 3.8%
Amounts 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.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with
original maturities of three months or less.
Operating Revenues
Revenues include the accrual of 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. If the Company's earnings exceed the allowed
return in the Indiana jurisdiction, the fuel clause mechanism provides for
the refunding of the excess earnings to ratepayers. Wholesale
jurisdictional fuel cost changes are expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs
Incremental operation and maintenance costs associated with refueling
outages at the Donald C. Cook Nuclear Plant (Cook Plant) are deferred
for amortization over the period (generally eighteen months) beginning with
the commencement of an outage and ending with the beginning of the next
outage.
Income Taxes
The Company follows the liability method of accounting for income taxes
as prescribed by SFAS 109, Accounting for Income Taxes. Under the
liability method, deferred income taxes are provided for all temporary
differences between book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in rates, regulatory
assets and liabilities are recorded in accordance with SFAS 71.
Investment Tax Credits
Based on directives of regulatory commissions, the Company reflected
investment tax credits in rates on a deferral basis. Commensurate with
rate treatment deferred investment tax credits are being amortized over the
life of the related plant investment. The Company's policy with regard to
investment tax credits for nonutility property was to practice the flow-
through method of accounting.
Debt and Preferred Stock
Gains and losses on reacquired 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.
In accordance with rate-making treatment 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,
debited to paid-in capital and amortized to reduce retained earnings 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.
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
Securities held in trust funds for decommissioning nuclear facilities
and for the disposal of spent nuclear fuel are recorded at market value in
accordance with SFAS 115, Accounting for Certain Investments in Debt and
Equity Securities. Securities in the trust funds have been classified as
available-for-sale due to their long-term purpose. Due to the rate-making
process, adjustments for unrealized gains and losses are not reported in
equity but result in adjustments to regulatory assets and liabilities.
Other Property and Investments
Other property and investments are stated at cost.
Reclassifications
Certain prior-period amounts were reclassified to conform with current-
period presentation.
2. EFFECTS OF REGULATION AND PHASE-IN PLANS:
The consolidated financial statements include assets and liabilities
recorded in accordance with regulatory actions in order to match expenses
with the related revenues included in cost-based regulated rates.
Regulatory assets are expected to be recovered in future periods through
the rate-making process and regulatory liabilities are expected to reduce
future cost recoveries. The Company has reviewed all the evidence
currently available and concluded that it continues to meet the
requirements to apply SFAS 71. In the event a portion of
the Company s business no longer met these requirements regulatory assets
and liabilities would have to be written off for that portion of the
business.
Regulatory assets and liabilities are comprised of the following:
December 31,
1995 1994
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $309,640 $308,831
Department of Energy
Decontamination and
Decommissioning Assessment 48,862 51,896
Rate Phase-in Plan Deferrals 27,515 43,159
Nuclear Refueling
Outage Cost Levelization 23,467 32,151
Unamortized Loss On
Reacquired Debt 20,827 18,472
Other 28,214 27,598
Total Regulatory Assets $458,525 $482,107
Regulatory Liabilities:
Deferred Investment Tax Credits $155,202 $164,206
Other* 1,576 350
Total Regulatory Liabilities $156,778 $164,556
* Included in Deferred Credits on Consolidated Balance Sheets.
The Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.
I&M and AEP Generating Company (AEGCo), an affiliate, each own 50% of one
unit (Rockport 1) and lease a 50% interest in the other unit (Rockport 2)
from unaffiliated lessors under an operating lease. The gain on the sale
and leaseback of Rockport 2 was deferred and is being amortized, with
related taxes, over the initial lease term which expires in 2022.
Rate phase-in plans in the Company's Indiana and FERC jurisdictions for
its share of Rockport 1 provide for the recovery and straight-line
amortization through 1997 of prior-year deferrals. Unamortized deferred
amounts under the phase-in plans were $27.5 million and $43.2 million at
December 31, 1995 and 1994, respectively. Amortization was $16 million in
1995, 1994 and 1993.
3. COMMITMENTS AND CONTINGENCIES:
Construction and Other Commitments
Substantial construction commitments have been made. Such commitments
do not include any expenditures for new generating capacity. The aggregate
construction program expenditures for 1996-1998 are estimated to be $315
million.
Long-term fuel supply contracts contain clauses that provide for
periodic price adjustments. The retail jurisdictions have fuel clause
mechanisms that provide for recovery of changes in the cost of fuel with
the regulators' review and approval. The contracts are for various terms,
the longest of which extends to 2014, and contain various clauses that
would release the Company from its obligation under certain force majeure
conditions.
Unit Power Agreements
The Company is committed under unit power agreements to purchase 70% of
AEGCo's 1,300 mw Rockport Plant capacity unless it is sold to unaffiliated
utilities. AEGCo has one long-term contract with an unaffiliated utility
that expires in 1999 for 455 mw of Rockport Plant capacity.
The Company sells under contract up to 250 mw of Rockport Plant capacity
to an unaffiliated utility. The contract expires in 2009.
Litigation
In September 1995, the Indiana Supreme Court ruled in favor of the
Company when it denied an appeal of a March 1995 opinion from the Court of
Appeals of Indiana. The appeals court had upheld and affirmed a lower
court s decision. The case resulted from an earlier Supreme Court of
Indiana decision which overruled a lower court decision and voided an IURC
order assigning a customer to the Company. The Company had received
approximately $29 million in gross revenues from the customer which was not
in the Company s service territory. The lower court had dismissed the case
filed under a provision of Indiana law that allows a utility to seek damages
equal to the gross revenues received by the Company for rendering service in
the designated service territory of another utility.
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 or financial
condition.
Nuclear Plant
I&M owns and operates the two-unit 2,110 mw Cook Plant under licenses
granted by a regulatory authority. The operation of a nuclear facility
involves special risks, potential liabilities, and specific regulatory and
safety requirements. Should a nuclear incident occur at any nuclear power
plant facility in the United States, the resultant liability could be sub-
stantial. By agreement I&M is partially liable together with all other
electric utility companies that own nuclear generating units for a nuclear
power plant incident. In the event nuclear losses or liabilities are
underinsured or exceed accumulated funds and recovery is not possible,
results of operations and financial condition would be negatively affected.
Nuclear Incident Liability
Public liability is limited by law to $8.9 billion should an incident
occur at any licensed reactor in the United States. Commercially available
insurance provides $200 million of coverage. In the event of a nuclear
incident at any nuclear plant in the United States the remainder of the
liability would be provided by a deferred premium assessment of $79.3
million on each licensed reactor payable in annual installments of $10
million. As a result, I&M could be assessed $158.6 million per nuclear
incident payable in annual installments of $20 million. The number of
incidents for which payments could be required is not limited.
Nuclear insurance pools and other insurance policies provide $3.6 billion
of property damage, decommissioning and decontamination coverage for Cook
Plant. Additional insurance provides coverage for extra costs resulting
from a prolonged accidental Cook Plant outage. Some of the policies have
deferred premium provisions which could be triggered by losses in excess of
the insurer's resources. The losses could result from claims at the Cook
Plant or certain other non-affiliated nuclear units. The Company could be
assessed up to $40.9 million annually under these policies.
Spent Nuclear Fuel Disposal
Federal law provides for government responsibility for permanent spent
nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel
disposal. A fee of one mill per kilowatthour for fuel consumed after April
6, 1983 is being collected from customers and remitted to the U.S. Trea-
sury. Fees and related interest of $163 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 various factors including
continued delays and uncertainties related to the federal disposal program.
At December 31, 1995, funds collected from customers to eventually pay the
pre-April 1983 fee and related earnings including accrued interest
approximated the liability.
Decommissioning and Low Level Waste Accumulation Disposal
Decommissioning costs are accrued over the service life of the Cook Plant.
The licenses to operate the two nuclear units expire in 2014 and 2017.
After expiration of the licenses the plant is expected to be decommissioned
through dismantlement. The Company s latest estimate for decommissioning
and low level radioactive waste accumulation disposal costs range from $634
million to $988 million in 1993 nondiscounted dollars. The wide range is
caused by variables in assumptions including the estimated length of time
spent nuclear fuel must be stored at the plant subsequent to ceasing
operations which depends on future developments in the federal government's
spent nuclear fuel disposal program. Continued delays in the federal fuel
disposal program can result in increased decommissioning costs. Decommis-
sioning costs are being recovered in the 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
which was $30 million in 1995, $26 million in 1994 and $13 million in 1993.
Decommissioning amounts recovered from customers are deposited in external
trusts. Trust fund earnings increase the fund assets and the recorded
liability and decrease the amount to be recovered from ratepayers. At
December 31, 1995 the Company has recognized a decommissioning liability of
$269 million.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the System's generating plants are shared by members
of the Power Pool. The Company is a member of the Power Pool. Under the
terms of the System Interconnection Agreement, capacity charges and credits
are designed to allocate the cost of the System's capacity among the Power
Pool members based on their relative peak demands and generating reserves.
Power Pool members are also compensated for the out-of-pocket costs of
energy delivered to the Power Pool and charged for energy received from the
Power Pool. The Company is a net supplier to the pool and, therefore,
receives net capacity credits from the Power Pool.
Operating revenues includes revenues for supplying energy and capacity to
the Power Pool as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Capacity Revenues $ 59,918 $ 88,183 $ 86,050
Energy Revenues 83,799 52,274 118,533
Total $143,717 $140,457 $204,583
Purchased power expense includes charges of $25.4 million in 1995, $33.1
million in 1994 and $20.9 million in 1993 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 of the Power Pool wholesale sales
included in operating revenues were $52.6 million in 1995, $54.1 million in
1994 and $57 million in 1993.
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
$10.7 million in 1995, $14.2 million in 1994 and $5.1 million in 1993.
Revenues from these transactions including a transmission fee are included
in the above Power Pool wholesale operating revenues.
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 $85.2 million, $82.4 million and $78.9 million in 1995, 1994 and
1993, 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, other operation expense includes equalization credits of
$46.7 million, $50.3 million and $47.4 million in 1995, 1994 and 1993,
respectively.
Revenues from providing barging services were recorded in nonoperating
income as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Affiliated Companies $23,160 $24,001 $21,332
Unaffiliated Companies 6,992 5,021 5,757
Total $30,152 $29,022 $27,089
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are billed by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the
use of equity capital, which is furnished to AEPSC by AEP Co., Inc.
Billings from AEPSC are capitalized or expensed depending on the nature of
the services rendered. AEPSC and its billings are subject to the
regulation of the SEC under the 1935 Act.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employ-
ees meeting eligibility requirements. Benefits are based on service years
and compensation levels. Pension costs are allocated by first charging
each System company with its service cost and then allocating the remaining
pension cost in proportion to its share of the projected benefit
obligation. The funding policy is to make annual trust fund contributions
equal to the net periodic pension cost up to the maximum amount deductible
for federal income taxes, but not less than the minimum required contribu-
tion in accordance with the Employee Retirement Income Security Act of
1974.
Net pension costs for the years ended December 31, 1995, 1994 and 1993
were $2.7 million, $5 million and $4.7 million, respectively.
An employee savings plan is offered which allows participants to
contribute up to 17% of their salaries into various investment alterna-
tives, including AEP Co., Inc. common stock. An employer matching
contribution, equaling one-half of the employees' contribution to the plan
up to a maximum of 3% of the employees' base salary, is invested in AEP
Co., Inc. common stock. The employer's annual contributions totaled $3.9
million in 1995 and 1994 and $3.5 million in 1993.
Postretirement benefits other than pensions (OPEB) are provided for
retired employees under an AEP System plan. Substantially all employees
are eligible for postretirement health care and life insurance if they have
at least 10 service years and are age 55 or older when employment
terminates.
SFAS 106, Employers Accounting for Postretirement Benefits Other Than
Pensions was adopted in January 1993 for the Company s aggregate liability
for OPEB. SFAS 106 requires the accrual during the employee s service
years of the present value liability for OPEB costs. Costs for the
accumulated postretirement benefits earned and not recognized at adoption
are being recognized, in accordance with SFAS 106, as a transition
obligation over 20 years. OPEB costs are determined by the application of
AEP System actuarial assumptions to each operating company's employee
complement. The annual accrued OPEB costs for employees and retirees re-
quired by SFAS 106, which includes the recognition of one-twentieth of the
prior service transition obligation, were $13.6 million in 1995, $13.2
million in 1994 and $12.4 million in 1993.
The Company received approval from the IURC to recover the increased OPEB
costs resulting from SFAS 106. In the Michigan and wholesale juris-
dictions, the Company received authority to defer under certain conditions
the increased OPEB costs which are not being currently recovered in rates.
Future recovery of any deferrals and increased OPEB costs will be sought in
the next base rate filings. At December 31, 1995 and 1994, $6.7 million of
incremental OPEB costs were deferred.
As a result of SFAS 106, a Voluntary Employees Beneficiary Association
(VEBA) trust fund for OPEB benefits was established and a corporate owned
life insurance (COLI) program was implemented to lower the net OPEB costs.
The insurance policies have a substantial cash surrender value which is
recorded, net of equally substantial policy loans, in other property and
investments. Legislation was passed by Congress which would
have significantly reduced the tax benefits of a COLI program in the future.
The legislation containing this provision
was vetoed by the President. At this time it is uncertain if legislation
repealing certain tax benefits for COLI programs will be enacted. If
enacted this legislation would negatively impact the effectiveness of the
COLI program as a funding and cost reduction mechanism.
The funding policy is to make VEBA trust fund contributions equal to the
increase in OPEB costs resulting from the implementation of SFAS 106.
These contributions include amounts collected from ratepayers and the net
earnings from the COLI program. Contributions to the VEBA trust fund were
$10.3 million in 1995, $6.6 million in 1994 and $1.3 million in 1993.
6. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1995 1994 1993
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $71,457 $68,946 $82,509
Income Taxes 88,675 85,854 68,303
Noncash Acquisitions
Under Capital
Leases were 32,073 92,199 15,467
In connection with the sale of western coal land and equipment the
Company will receive cash payments from the buyer of $31.5 million over a
six year period which has been recorded at a net present value of $26.9
million. In connection with construction of facilities to provide service
to a new customer the Company will receive cash payments of $20.9 million
plus accrued interest over 20 years.
7. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $ 75,686 $ 64,565 $ 93,974
Deferred (13,732) (18,057) (53,685)
Deferred Investment Tax Credits (7,929) (8,155) (8,308)
Total 54,025 38,353 31,981
Charged (Credited) to Nonoperating Income (net):
Current 12,872 1,390 6,026
Deferred (9,832) (1,718) 1,054
Deferred Investment Tax Credits (1,075) (5,722) (235)
Total 1,965 (6,050) 6,845
Total Federal Income Taxes as Reported $ 55,990 $ 32,303 $ 38,826
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,
1995 1994 1993
(in thousands)
Net Income $141,092 $157,502 $129,344
Federal Income Taxes 55,990 32,303 38,826
Pre-tax Book Income $197,082 $189,805 $168,170
Federal Income Tax on Pre-tax Book Income at
Statutory Rate (35%) $68,979 $ 66,432 $58,860
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Depreciation 8,954 (1,033) (747)
Adoption of SFAS 109 - - 5,271
Corporate Owned Life Insurance (5,187) (4,521) (4,697)
Nuclear Fuel Disposal Costs (3,060) (4,498) (2,432)
Amortization of Deferred Investment Tax Credits (net) (9,004) (13,875) (8,543)
Other (4,692) (10,202) (8,886)
Total Federal Income Taxes as Reported $55,990 $ 32,303 $38,826
Effective Federal Income Tax Rate 28.4% 17.0% 23.1%
The following tables show the elements of the net deferred tax liability
and the significant temporary differences that gave rise to it:
December 31,
1995 1994
(in thousands)
Deferred Tax Assets $ 221,604 $ 198,750
Deferred Tax Liabilities (833,751) (833,652)
Net Deferred Tax Liabilities $(612,147) $(634,902)
Temporary Differences
in Tax Dollars:
Property Related
Temporary Differences $(490,986) $(498,124)
Amounts Due From Customers
For Future Federal
Income Taxes (83,277) (81,812)
Deferred State Income Taxes (71,712) (71,712)
Deferred Net Gain -
Rockport Plant Unit 2 34,941 36,239
All Other (net) (1,113) (19,493)
Total Net Deferred
Tax Liabilities $(612,147) $(634,902)
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 to
the System companies giving rise to them in determining their current tax
expense. The tax loss of the System parent company, AEP Co., Inc., is
allocated to its subsidiaries with taxable income. With the exception of
the loss of the parent company, the method of allocation approximates a
separate return result for each company in the consolidated group.
The AEP System has settled with the Internal Revenue Service (IRS) all
issues from the audits of the consolidated federal income tax returns for
the years prior to 1991. Returns for the years 1991 through 1993 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.
8. FAIR VALUE OF FINANCIAL INSTRUMENTS:
Nuclear Trust Funds Recorded at Market Value
The trust investments are recorded at market value in accordance with SFAS
115 and consist primarily of tax-exempt municipal bonds.
At December 31, 1995 and 1994 the fair values of trust investments were
$434 million and $353 million, respectively. Accumulated gross unrealized
holding gains and losses were $19.1 million and $1.0 million, respectively,
at December 31, 1995. The change in market value during 1995 and 1994 was
a $24.9 million net holding gain and a $27.1 million net holding loss,
respectively.
The trust investments' cost basis by security type were:
December 31,
1995 1994
(in thousands)
Treasury bonds $ 14,963 $ 997
Tax-exempt bonds 336,073 332,098
Equity securities 24,101 1,665
Cash,cash equivalents
and interest accrued 40,356 25,304
Total $415,493 $360,064
Proceeds from sales and maturities of securities of $78.2 million during
1995 resulted in $1.4 million of realized gains and $0.3 million of
realized losses. Proceeds from sales and maturities of securities of $20.1
million during 1994 resulted in $52,000 of realized gains and $155,000 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, 1995, the year of maturity of trust fund investments,
other than equity securities, was:
(in thousands)
1996 $ 55,748
1997-2000 96,882
2001-2005 162,563
After 2005 76,199
Total $391,392
Other Financial Instruments Recorded at Historical Cost
The carrying amounts of cash and cash equivalents, accounts receivable,
short-term debt, and accounts payable approximate fair value because of the
short-term maturity of these instruments. Fair values for preferred
stocks subject to mandatory redemption were $140 million and $117 million
and for long-term debt were $1.1 billion and $1.0 billion at December 31,
1995 and 1994, respectively. The carrying amounts for preferred stock
subject to mandatory redemption were $135 million at each year end and
for long-term debt were $1.0 billion
and $1.1 billion at December 31, 1995 and 1994, respectively. Fair values
are based on quoted market prices for the same or similar issues and the
current dividend or interest rates offered for instruments of the same
remaining maturities. The carrying amount of the pre-April 1983 spent
nuclear fuel disposal liability approximates the Company's best estimate of
its fair value.
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.
Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1995 1994
(in thousands)
Electric Utility Plant:
Production $ 9,346 $ 8,371
Distribution 14,753 14,717
General:
Nuclear Fuel
(net of amortization) 69,442 89,478
Other 54,554 53,781
Total Electric Utility
Plant 148,095 166,347
Accumulated Amortization 24,933 27,225
Net Electric Utility
Plant 123,162 139,122
Other Property 22,361 15,842
Accumulated Amortization 3,017 2,375
Net Other Property 19,344 13,467
Net Properties under
Capital Leases $142,506 $152,589
Capital Lease Obligations:
Noncurrent Liability $110,730 $113,586
Liability Due Within
One Year 31,776 39,003
Total Capital
Lease Obligations $142,506 $152,589
The noncurrent portion of capital lease obligations is included in other
noncurrent liabilities.
Properties under operating leases and related obligations are not included
in the Consolidated Balance Sheets.
Lease rentals are generally charged to operating expenses in accordance
with rate-making treatment. The components of rental costs are as follows:
Year Ended December 31,
1995 1994 1993
(in thousands)
Operating Leases $ 96,472 $104,519 $103,884
Amortization of
Capital Leases 45,843 30,875 46,063
Interest on
Capital Leases 9,987 7,643 8,873
Total Rental
Costs $152,302 $143,037 $158,820
Future minimum lease payments consisted of the following at December 31,
1995:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1996 $ 13,765 $ 98,357
1997 12,518 96,593
1998 10,620 91,454
1999 9,389 91,312
2000 8,275 91,165
Later Years 44,362 1,840,723
Total Future Minimum
Lease Payments 98,929(a) $2,309,604
Less Estimated
Interest Element 25,865
Estimated Present
Value of Future
Minimum Lease
Payments 73,064
Unamortized Nuclear
Fuel 69,442
Total $142,506
(a) Excludes nuclear fuel rentals which are paid in proportion to heat
produced and carrying charges on the unamortized nuclear fuel
balance. There are no minimum lease payment requirements for leased
nuclear fuel.
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1995, 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. During 1994 the
Company redeemed and cancelled 350,000 shares of the 7.76% series. During
1993 the Company redeemed and cancelled the following entire series: 8.68%
series consisting of 300,000 shares and $2.15 and $2.25 series each
consisting of 1,600,000 shares.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Outstanding December 31,
Series 1995 Value December 31, 1995 1995 1994
(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
$ 52,000 $ 52,000
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Outstanding December 31.
Series(a) Value December 31, 1995 1995 1994
(in thousands)
5.90% (b) $100 400,000 $ 40,000 $ 40,000
6-1/4%(c) 100 300,000 30,000 30,000
6.30% (d) 100 350,000 35,000 35,000
6-7/8%(e) 100 300,000 30,000 30,000
$135,000 $135,000
(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 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 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.
(d) Shares issued February 1994. Commencing in 2004 and continuing through
the year 2008, a sinking fund will require the redemption of 17,500
shares each year and the redemption of the remaining shares outstanding on
July 1, 2009, in each case at $100 per share.
(e) Shares issued February 1993. 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.
11. LONG-TERM DEBT AND LINES OF CREDIT:
Long-term debt by major category was outstanding as follows:
December 31,
1995 1994
(in thousands)
First Mortgage Bonds $ 562,017 $ 561,770
Installment Purchase
Contracts 308,971 308,087
Other Long-term Debt(a) 163,060 153,977
Notes Payable to Banks - 40,000
Sinking Fund Debentures(b) 6,053 6,053
1,040,101 1,069,887
Less Portion Due Within
One Year 6,053 140,000
Total $1,034,048 $ 929,887
(a) Nuclear Fuel Disposal Costs including interest accrued. See Note 3.
(b) Called for redemption on March 1, 1996.
First mortgage bonds outstanding were as follows:
December 31,
1995 1994
(in thousands)
% Rate Due
7 1998 - May 1 $ 35,000 $ 35,000
7.30 1999 - December 15 35,000 35,000
7.63 2001 - June 1 40,000 40,000
7.60 2002 - November 1 50,000 50,000
7.70 2002 - December 15 40,000 40,000
6.80 2003 - July 1 20,000 20,000
6.55 2003 - October 1 20,000 20,000
6.10 2003 - November 1 30,000 30,000
6.55 2004 - March 1 25,000 25,000
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 20,000
7.35 2023 - October 1 20,000 20,000
7.20 2024 - February 1 40,000 40,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (net) (2,983) (3,230)
Total $562,017 $561,770
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,
1995 1994
(in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7 2015 - April 1 $ 25,000 $ 25,000
5.9 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
9-1/4 2014 - August 1 - 50,000
6-3/4 2014 - August 1 - 50,000
(a) 2014 - August 1 50,000 50,000
7.6 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 -
(b) 2025 - June 1 50,000 -
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (3,029) (3,913)
308,971 308,087
Less Portion Due
Within One Year - 100,000
Total $308,971 $208,087
(a) The variable interest rate is determined weekly. The average
weighted interest rate was 4.6% for 1995 and 3.8% for 1994.
(b) The adjustable interest rate can be a daily, weekly,
commercial paper or term rate as designated by the Company.
Initially, a weekly rate was selected during 1995 which ranged
from 2.9% to 5% and averaged 4.0%.
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 variable 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 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.
At December 31, 1995, annual long-term debt payments, excluding premium
or discount, are as follows:
Principal Amount
(in thousands)
1996 $ 6,053
1997 -
1998 35,000
1999 35,000
2000 50,000
Later Years 920,060
Total $1,046,113
Short-term debt borrowings are limited by provisions of the 1935 Act to
$175 million. Lines of credit are shared with AEP System companies and at
December 31, 1995 and 1994 were available in the amounts of $372 million
and $558 million, respectively. Commitment fees of approximately 1/8 of 1%
of the unused short-term lines of credit are paid each year to the banks to
maintain the lines of credit. Outstanding short-term debt consisted of:
Year-end
Balance Weighted
Outstanding Average
(in thousands) Interest Rate
December 31, 1995:
Note Payable $52,200 6.1%
Commercial Paper 37,775 6.1
Total $89,975 6.1
December 31, 1994:
Commercial Paper $50,600 6.3%
12. COMMON SHAREHOLDER'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, 1995, $5.9 million of retained earnings were restricted. Regulatory
approval is required to pay dividends out of paid-in capital.
The Company received from AEP Co., Inc. a cash capital contribution of $10
million in 1993 which was credited to paid-in capital. In 1995, 1994 and
1993 net charges to paid-in capital of $2,548,000, $422,000 and $1,224,000,
respectively, represented expenses of issuing and retiring cumulative
preferred stock. There were no other transactions affecting the common
stock and paid-in capital accounts in 1995, 1994 and 1993.
13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1995
March 31 $327,177 $56,311 $38,388
June 30 307,820 51,386 33,780
September 30 334,846 54,400 37,404
December 31 313,314 43,626 31,520
1994
March 31 337,921 58,875 44,976
June 30 310,104 54,691 37,281
September 30 317,061 55,469 37,736
December 31 286,223 52,934 37,509