I&M 1996 ANNUAL REPORT
Selected Consolidated Financial Data
Year Ended December 31,
1996 1995 1994 1993 1992
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,328,493 $1,283,157 $1,251,309 $1,202,643 $1,196,755
Operating Expenses 1,108,076 1,077,434 1,029,340 992,485 1,000,967
Operating Income 220,417 205,723 221,969 210,158 195,788
Nonoperating Income (Loss) 2,729 6,272 7,428 (234) 14,115
Income Before Interest Charges 223,146 211,995 229,397 209,924 209,903
Interest Charges 65,993 70,903 71,895 80,580 85,920
Net Income 157,153 141,092 157,502 129,344 123,983
Preferred Stock Dividend Requirement 10,681 11,791 11,681 14,256 15,452
Earnings Applicable to Common Stock $ 146,472 $ 129,301 $ 145,821 $ 115,088 $ 108,531
December 31,
1996 1995 1994 1993 1992
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,377,669 $4,319,564 $4,269,306 $4,290,957 $4,266,480
Accumulated Depreciation and
Amortization 1,861,893 1,751,965 1,659,940 1,714,829 1,631,438
Net Electric Utility Plant $2,515,776 $2,567,599 $2,609,366 $2,576,128 $2,635,042
Total Assets $3,897,484 $3,928,337 $3,878,035 $3,723,648 $3,608,645
Common Stock and Paid-in Capital $ 787,856 $ 787,686 $ 790,234 $ 790,625 $ 781,818
Retained Earnings 269,071 235,107 216,658 177,638 171,309
Total Common Shareholder's Equity $1,056,927 $1,022,793 $1,006,892 $ 968,263 $ 953,127
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption $ 21,977 $ 52,000 $ 52,000 $ 87,000 $ 197,000
Subject to Mandatory Redemption (a) 135,000 135,000 135,000 100,000 -
Total Cumulative Preferred Stock $ 156,977 $ 187,000 $ 187,000 $ 187,000 $ 197,000
Long-term Debt (a) $1,042,104 $1,040,101 $1,069,887 $1,073,154 $1,211,623
Obligations Under Capital Leases (a) $ 130,965 $ 142,506 $ 152,589 $ 98,753 $ 126,689
Total Capitalization and Liabilities $3,897,484 $3,928,337 $3,878,035 $3,723,648 $3,608,645
(a) Including portion due within one year.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
Business Outlook
With the issuance of two Federal Energy Regulatory Commission (FERC)
orders and the commencement of planning for retail competition at the state
level, we are in a better position to identify and develop strategies for
addressing the issues that face the American Electric Power (AEP) System,
Indiana Michigan Power Company and our changing industry. The industry's
adjustment to greater competition in generation and sales of electricity,
customer choice and the ability to fully recover costs will probably be the
most significant factors affecting the Company's future profitability.
Although the Company, as a member of the AEP System, has the financial
strength, geographic reach, location and cost structure to be an able
competitor, no assurance can be given that this position can be maintained.
However, we intend to make every effort to maintain and strengthen our
competitive position. We see a link between a smooth transition to a
competitive marketplace and maintaining a strong financial position.
The new FERC orders facilitate increased competition in both the
generation and sale of bulk power to wholesale customers. They provide,
among other things, for open access to transmission facilities. AEP's
support of the FERC's open access transmission rule is evidenced by our being
among the first to file a comparability tariff, offering access to AEP's
transmission grid at 143 interconnections to all parties under the same terms
and conditions available to AEP affiliates. This has provided greater
opportunities for transmission service sales.
Although customer choice proposals and discussions are under way in the
states in which we operate, it is difficult to predict their result and the
timing of changes, if any. We are actively involved in discussions on the
state and federal level regarding whether to and how best to transition to
competition in order to represent the best interests of our customers,
shareholders and employees. We favor an orderly and smooth transition to a
more competitive energy market because we believe that AEP will do better in
the long term if it is free to compete.
If the electric energy market evolves from cost-of-service rate-making
to market-based pricing, many complex issues must be resolved, including the
recovery of stranded costs. While the new FERC orders provide, under
certain conditions, for recovery of stranded costs at the wholesale level,
the issue of stranded cost recovery remains open at the much larger state
retail level.
Stranded Costs
Stranded costs occur when a customer switches to a new supplier for its
electric energy needs or when a component of the business, for example
generation, is no longer subject to cost-based regulation, creating the issue
of who pays for plant investment, purchased power or fuel contracts both
non-affiliated and affiliated, inventories, construction work in progress,
nuclear decommissioning, plant removal and shutdown costs, previously
deferred costs (regulatory assets) and other investments and commitments that
are no longer needed, economic or recoverable in a competitive market. The
amount of any stranded costs the Company may experience depends on the timing
of and the extent to which direct competition is introduced to our business
and the then-existing market price of energy.
Under the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation,"
regulatory assets (deferred expenses) and regulatory liabilities (deferred
revenues) are included in the consolidated financial statements in accordance
with regulatory actions to match expenses and revenues in cost-based rates.
In the event a portion of the business no longer met the requirements of SFAS
71, net regulatory assets would have to be written off for that portion of
the business and assets tested for possible impairment. Whether an
impairment exists would depend on how low the market price of energy is in
competition relative to the cost of energy.
Among other requirements the application of SFAS 71 requires that the
rates charged customers be cost based. Our generation business is still
cost-based regulated and should remain so for the foreseeable future. Should
enabling state legislation be enacted we believe there should be at least a
three to five year transition to full competition. Although the recent FERC
orders provide for competition in the firm wholesale market, that market is a
relatively small part of our business and our firm wholesale sales are still
under cost-of-service contracts. We believe that enabling state
legislation if enacted should provide for a sufficient transition period to
allow for the recovery of any generation-related stranded costs and
we are dedicating ourselves to work with regulators, customers and
legislators to accomplish both an orderly transition and a reasonable and
fair disposition of the stranded cost issue. However, if the Company were to
no longer be cost-based regulated and recovery of stranded costs were not
possible, results of operations and financial condition would be adversely
affected.
Since state commissions have jurisdiction over the sale and distribution
of electricity to retail customers, we believe that state legislation and
regulation should shape the future competitive market for electricity while
federal legislation should seek to ensure reciprocity among the states and a
level playing field for all power suppliers. Presently states with higher
cost power, like California, are aggressively pursuing deregulation. The
states the Company operates in, however, are generally addressing the call
for customer choice more cautiously.
Restructuring/Functional Unbundling
In 1996 we took some major steps to maintain and enhance the Company's
competitive strength. We restructured our management and operations to allow
us to comply with the new FERC orders which required separation of generation
and energy sales operations from our energy transmission and delivery
operations. This has achieved and should continue to achieve staffing,
managerial and operating efficiencies. The generation and marketing business
units are preparing for the possibility of competition in an open market for
customers. Our energy delivery business expects to remain regulated and
ultimately be subject to some form of incentive or performance-based
ratemaking. If competition never replaces regulation we will be a more
efficient and productive business as a result of our preparations which
should benefit all concerned.
Marketing and customer service efforts have been enhanced with programs
like the Key Accounts Program which strives to build strong partnerships with
key customers in order to build customer loyalty. In 1996 we also launched a
series of new television commercials to inform our customers that we will be
operating under the name, American Electric Power. The commercials are
intended to position AEP as more than just a supplier of electricity. We
want to be the energy and energy services provider of choice; AEP: America's
Energy Partner.
Cost Containment
In 1996 we continued our efforts to reduce costs in order to maintain
our competitiveness. Reviews of our major processes led to decisions to
consolidate the management and operations of internal service functions
performed at multiple locations. Among the functions being consolidated are
fossil generation plant maintenance, nuclear operations, system operations,
accounting and load research. A study of the Company's procurement and
supply chain operations led to cost reductions through better inventory
management, just-in-time delivery and the increased use of electronic
purchasing. Also in 1996 we completed the installation of an activity based
management budgeting system. This tool will enable managers to better
analyze work and control costs. While staff reductions and cost savings are
being achieved in these and other areas, expenses for new marketing programs,
customer services and modern efficient management information systems are
being increased to prepare for competition. These expenditures for the
future should produce further improvements and efficiencies, enabling the
Company to maintain its position as a low-cost producer.
Fuel Costs
Coal is 30% of the production cost of electricity. Although our coal
costs per unit of electricity (per kwh) have declined we recognize that we
must continue to manage our coal costs to maintain our competitive position.
As long-term coal supply contracts expire we are negotiating with non-affiliated
suppliers to lower purchased coal costs. We intend to continue to
prudently supplement our long-term coal supplies with spot market purchases
as long as favorable spot market prices exist.
Nuclear Cost
Significant efforts have been made to enhance our competitiveness by
improving the efficiency of the Company's nuclear operations. Net generation
in 1996 for the Company's only nuclear plant, the two-unit Donald C. Cook
Nuclear Plant, located on the shores of Lake Michigan, was 16,396 gigawatts,
the highest in the plant's 20-year history. The generation record was set in
part due to Unit 2's best continuous run in its history, 226 days, reached in
December 1996. Refueling costs and related outage time have been reduced.
We also reduced nuclear staff support costs in 1996 by relocating our
Columbus-based nuclear management and support staff to Michigan to
consolidate it with the plant staff.
It is difficult to reduce nuclear generation costs since major cost
components are impacted by federal laws and Nuclear Regulatory Commission
(NRC) regulations. The Nuclear Waste Policy Act of 1982 established federal
responsibility for the permanent off-site disposal of spent nuclear fuel and
high-level radioactive waste. By law we participate in the Department of
Energy's (DOE's) Spent Nuclear Fuel (SNF) disposal program which is described
in Note 3 of the Notes to Consolidated Financial Statements. Since 1983 our
customers have paid $254 million for the disposal of spent nuclear fuel
consumed at the Cook Nuclear Plant. Under the provisions of the Nuclear
Waste Policy Act, collections from customers are to provide the DOE with
money to build a repository for spent fuel. To date the federal government
has not made sufficient progress towards a permanent repository or otherwise
assuming responsibility for SNF. As long as there is a delay in the storage
repository for SNF, the cost of both temporary and permanent storage will
continue to increase.
The cost to decommission the Cook Nuclear Plant is also affected by NRC
regulations and the DOE's SNF disposal program. Studies completed in 1994
estimate the cost to decommission the Cook Nuclear Plant and dispose of low-
level nuclear waste accumulation to range from $634 million to $988 million
in 1993 nondiscounted dollars. This estimate could increase due to
uncertainty in the DOE's SNF disposal program and the length of time that SNF
may need to be stored at the plant site delaying decommissioning. Presently
we are recovering the estimated cost of decommissioning the Cook Nuclear
Plant over its remaining life. However, the Company's future results of
operations and possibly its financial condition could be adversely affected
if the cost of spent nuclear fuel disposal and decommissioning continues to
increase and cannot be recovered in regulated rates or as a stranded cost in
a future competitive market.
Environmental Matters
We take great pride in our efforts to economically produce and deliver
electricity while minimizing the impact on the environment. Indiana Michigan
Power Company has spent hundreds of millions of dollars to equip our
facilities with the latest economical clean air and water technologies and to
research possible new technologies. We intend to continue to take a
leadership role to foster economically prudent efforts to protect and
preserve the environment.
By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and spent nuclear fuel. Coal
combustion by-products are typically disposed of or treated in captive
disposal facilities or are beneficially utilized. In addition, our
generating plants and transmission and distribution facilities have used
asbestos, polychlorinated biphenyls (PCBs) and other hazardous and non-hazardous
materials. The Company is currently incurring costs to safely
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) addresses clean-up of hazardous substances at disposal
sites and authorized the United States Environmental Protection Agency
(Federal EPA) to administer the clean-up programs. As of year-end 1996, I&M
is currently involved in litigation with respect to two sites, and has been
named by the Federal EPA as a "Potentially Responsible Party" (PRP) for two
other sites. There are five additional sites for which the Company has
received information requests which could lead to PRP designation as well as
information requests for two state administered sites. I&M's 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
incurred for cleanup, future results of operations and possibly financial
condition would be adversely affected unless the costs can be recovered.
Results of Operations
In 1996 net income increased $16 million or 11%. The increase is mainly
attributable to increased wholesale sales, a reduction in maintenance expense
and reduced financing costs. Also contributing to the 1996 increase were
severance pay charges recorded in 1995 in connection with realigning
operations and management and gains recorded in 1996 from emission allowance
transactions. Although revenues increased 2.5% in 1995, net income declined
$16 million or 10% as the result of 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.
Operating Revenues and Energy Sales Increase
Operating revenues increased 3.5% in 1996 following a 2.5% increase in
1995. The price, volume analysis of revenue variances which accounted for the
improved results are:
Increase (Decrease)
From Previous Year
(dollars in millions) 1996 1995
Amount % Amount %
Retail:
Price Variance $(25.9) $ (0.7)
Volume Variance 32.8 29.9
6.9 0.8 29.2 3.3
Wholesale:
Price Variance (55.6) (116.9)
Volume Variance 89.6 121.4
34.0 9.5 4.5 1.3
Other Operating Revenues 4.4 (1.9)
Total $ 45.3 3.5 $ 31.8 2.5
Operating revenues increased in 1996 primarily as a result of increased
wholesale sales attributable to increased internal generation being supplied
to the AEP System Power Pool (Power Pool) and unaffiliated utilities. The
Company's share of Power Pool allocated sales increased 40% due to increased
transactions with other utilities and power marketers. During 1996 the
Company provided a new product, coal conversion services, to power marketers
and unaffiliated utilities resulting in 1.2 billion kilowatthours of
electricity being generated under a new FERC-approved interruptible tariff.
Under this tariff the Company converts the coal of a wholesale customer to
electricity for a fee.
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 and a colder fourth quarter in
1995 than in 1994 and continued growth in the number of retail customers.
While wholesale energy sales increased 34%, wholesale revenues increased by
only 1% in 1995. The substantial increase in wholesale energy sales was
primarily due to a 69% increase in energy sales to the Power Pool reflecting
the increased availability of the Company's 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. Sales to the Company's
municipal and cooperative customers and to unaffiliated utilities by the
Power Pool increased primarily due to weather related factors in 1995 versus
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,
which 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, were lower reflecting the effect of an
increase in the Company's peak demand during 1995.
Operating Expenses Increase
Total operating expenses increased 2.8% in 1996 or $30.6 million mainly
due to the increased operation of the Company's nuclear units, increased
Power Pool wholesale transactions, and higher income taxes partially offset
by significant reductions in maintenance expense. In 1995, total operating
expenses rose 4.7% or $48.1 million reflecting the increased operation of the
Company's nuclear units and severance pay accruals. The significant changes
in operating expenses were:
Increase (Decrease)
From Previous Year
dollars in millions) 1996 1995
Amount % Amount %
Fuel $ 13.3 6.0 $ 21.2 10.5
Purchased Power 13.3 10.6 (5.8) (4.4)
Other Operation 3.5 1.2 10.3 3.5
Maintenance (26.5) (18.7) 2.4 1.7
Federal Income Taxes 23.5 43.5 15.7 40.9
Fuel expense increased in 1996 due to a 17% increase in nuclear
generation made possible by the shorter refueling outage in 1996 versus an
extended refueling and maintenance outage in 1995. This increase was
partially offset by a lower average price per ton of coal consumed from a
favorable settlement of a coal transportation dispute. Fuel expense increased
substantially in 1995 due to a 51% increase in nuclear generation reflecting
the increased availability from having only one refueling outage in 1995
versus two in 1994.
The 1996 rise in purchased power expense was mainly due to additional
power purchases under an agreement with the Ohio Valley Electric Corporation,
an affiliated company which is not a member of the Power Pool, and increased
purchases from the Power Pool to support the Company's allocated share of
higher Power Pool wholesale transactions with non-affiliated utilities. The
1995 reduction in purchased power expense can be attributed to increased
availability of the Company's nuclear generation.
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.
Maintenance expense was substantially lower in 1996 due to
cost-reduction measures at the Company's nuclear plant, which reduced the
number of employees performing maintenance and lowered payments for contract
maintenance labor.
The increase in 1996 federal income taxes resulted from an increase in
pre-tax operating income and changes in certain book/tax differences
accounted for on a flow-through basis for rate-making purposes. Federal
income taxes increased in 1995 primarily due to changes in certain book/tax
timing 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.
Financing Costs
A decline in interest charges occurred in 1996 due to debt repayments
and a refinancing program which lowered interest rates.
Construction Spending
Gross plant and property additions were $144 million in 1996 and $151
million in 1995. Management estimates construction expenditures for the next
three years to be $340 million with no major new generating plant
construction planned. The funds for construction of new facilities and
improvement of existing facilities can come from a combination of internally
generated funds, short-term and long-term borrowings, preferred stock
issuances and investments in common equity by the Company's parent, American
Electric Power Company, Inc. (AEP Co., Inc.) However, all of the
construction expenditures for the next three years are expected to be
financed with internally generated funds.
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, 1996, $409 million of unused short-term
lines of credit shared with other AEP System companies were available.
Short-term debt borrowings are limited by provisions of the Public Utility
Holding Company Act of 1935 to $175 million. 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's earnings coverage presently exceeds all minimum coverage
requirements for the issuance of mortgage bonds and preferred stock. The
minimum coverage ratios are 2.0 for mortgage bonds and 1.5 for preferred
stock. At December 31, 1996, the mortgage bonds and preferred stock coverage
ratios were 6.66 and 3.07, respectively.
In January 1997 a tender offer was announced for all of the Company's
preferred stock in conjunction with a special meeting scheduled to be held on
February 28, 1997. The special meeting's purpose is to consider amendments
to the Company's articles of incorporation to remove certain capitalization
ratio requirements. These restrictions limit the Company's financial
flexibility and could place it at a competitive disadvantage in the future.
The amount paid to redeem the preferred stock that is tendered could total as
much as $154 million. A combination of short-term debt and unsecured
long-term debt is expected to be used to pay for the preferred stock tendered.
Litigation
The Company is involved in a number of legal proceedings and claims.
While we are unable to predict the outcome of such litigation, it is not
expected that the ultimate resolution of these matters will have a material
adverse effect on the results of operations and/or financial condition.
Effects of Inflation
Inflation affects the Company's cost of replacing utility plant and the
cost of operating and maintaining plant. The rate-making process generally
limits our recovery to the historical cost of assets resulting in economic
losses when the effects of inflation are not recovered from customers on a
timely basis. However, economic gains that result from the repayment of
long-term debt with inflated dollars partly offset the negative impact of
inflation.
Corporate Owned Life Insurance
In connection with the audit of the AEP System's 1991, 1992 and 1993
consolidated federal income tax returns the Internal Revenue Service (IRS)
agents sought a ruling from the IRS National Office that certain interest
deductions relating to a corporate owned life insurance (COLI) program should
not be allowed. The Company established the COLI program in 1990 as a part
of its strategy to fund and reduce the cost of medical benefits for retired
employees. AEP filed a brief with the IRS National Office refuting the
agents' position. Although no adjustments have been proposed, a disallowance
of the COLI interest deductions through December 31, 1996 would reduce
earnings by approximately $51 million (including interest). Management
believes it will ultimately prevail on this issue and will vigorously contest
any disallowance that may be assessed.
In 1996 Congress enacted legislation that prospectively phases out the
tax benefits for COLI interest deductions over a three year period beginning
in 1996. As a result the Company intends to restructure its COLI program.
The restructuring of the COLI program is not expected to have a material
impact on results of operations.
New Accounting Rule
In 1996 the Financial Accounting Standards Board (FASB) issued an
exposure draft "Accounting for Certain Liabilities Related to Closure or
Removal of Long-Lived Assets." The Company generally records such
liabilities over the life of its plant commensurate with rate recovery. The
exposure draft proposes that the present value of decommissioning and
certain other closure or removal obligations 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.
However, as a cost-based rate-regulated entity, the Company would expect to
record a corresponding regulatory asset for the cumulative effect of
initially applying the new standard. The FASB is reconsidering several
aspects of the exposure draft. It is unclear at this time what, if any,
changes the FASB will make to the proposal. Until it becomes apparent what
the FASB will decide and how certain questions raised by the exposure draft
are resolved the Company cannot determine its ultimate 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, 1996 and 1995,
and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1996.
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, 1996 and 1995, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1996 in conformity with generally accepted
accounting principles.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 25, 1997
Consolidated Statements of Income
Year Ended December 31,
1996 1995 1994
(in thousands)
OPERATING REVENUES $1,328,493 $1,283,157 $1,251,309
OPERATING EXPENSES:
Fuel 236,237 222,967 201,739
Purchased Power 138,687 125,413 131,234
Other Operation 310,513 306,967 296,625
Maintenance 115,300 141,813 139,423
Depreciation and Amortization 140,437 138,814 136,244
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals 15,644 15,644 15,644
Taxes Other Than Federal Income Taxes 73,729 71,791 70,078
Federal Income Taxes 77,529 54,025 38,353
Total Operating Expenses 1,108,076 1,077,434 1,029,340
OPERATING INCOME 220,417 205,723 221,969
NONOPERATING INCOME 2,729 6,272 7,428
INCOME BEFORE INTEREST CHARGES 223,146 211,995 229,397
INTEREST CHARGES 65,993 70,903 71,895
NET INCOME 157,153 141,092 157,502
PREFERRED STOCK DIVIDEND REQUIREMENTS 10,681 11,791 11,681
EARNINGS APPLICABLE TO COMMON STOCK $ 146,472 $ 129,301 $ 145,821
See Notes to Consolidated Financial Statements.
Consolidated Statements of Cash Flows
Year Ended December 31,
1996 1995 1994
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 157,153 $ 141,092 $ 157,502
Adjustments for Noncash Items:
Depreciation and Amortization 148,123 148,441 146,966
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) 7,662 8,684 (18,779)
Deferred Federal Income Taxes (24,687) (23,564) (19,775)
Deferred Investment Tax Credits (8,729) (9,004) (13,877)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,235) 4,121 (7,200)
Fuel, Materials and Supplies 903 (6,255) (3,423)
Accrued Utility Revenues 5,642 (3,355) (5,940)
Accounts Payable 1,186 (2,431) 5,219
Taxes Accrued (6,296) 8,075 9,148
Other (net) 7,975 (23,099) (12,145)
Net Cash Flows From Operating Activities 294,341 258,349 253,340
INVESTING ACTIVITIES:
Construction Expenditures (95,046) (117,785) (118,094)
Long-term Receivable from Customer
for Construction of Facilities 62 (18,733) -
Proceeds from Sales of Property and Other 2,714 9,325 2,038
Net Cash Flows Used For Investing Activities (92,270) (127,193) (116,056)
FINANCING ACTIVITIES:
Issuance of Cumulative Preferred Stock - - 34,618
Issuance of Long-term Debt 38,579 96,819 89,221
Retirement of Cumulative Preferred Stock (30,568) - (35,798)
Retirement of Long-term Debt (46,091) (141,122) (101,833)
Change in Short-term Debt (net) (46,475) 39,375 525
Dividends Paid on Common Stock (112,508) (110,852) (106,608)
Dividends Paid on Cumulative Preferred Stock (10,498) (11,560) (11,254)
Net Cash Flows Used For Financing Activities (207,561) (127,340) (131,129)
Net Increase (Decrease) in Cash and
Cash Equivalents (5,490) 3,816 6,155
Cash and Cash Equivalents January 1 13,723 9,907 3,752
Cash and Cash Equivalents December 31 $ 8,233 $ 13,723 $ 9,907
See Notes to Consolidated Financial Statements.
Consolidated Balance Sheets
December 31,
1996 1995
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,525,969 $2,507,667
Transmission 881,407 867,541
Distribution 696,069 666,810
General (including nuclear fuel) 189,619 186,959
Construction Work in Progress 84,605 90,587
Total Electric Utility Plant 4,377,669 4,319,564
Accumulated Depreciation and Amortization 1,861,893 1,751,965
NET ELECTRIC UTILITY PLANT 2,515,776 2,567,599
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 490,778 433,619
OTHER PROPERTY AND INVESTMENTS 154,265 150,994
CURRENT ASSETS:
Cash and Cash Equivalents 8,233 13,723
Accounts Receivable:
Customers 90,656 82,434
Affiliated Companies 13,727 21,881
Miscellaneous 21,439 11,450
Allowance for Uncollectible Accounts (156) (334)
Fuel - at average cost 23,977 29,093
Materials and Supplies - at average cost 77,074 72,861
Accrued Utility Revenues 38,295 43,937
Prepayments 10,271 10,191
TOTAL CURRENT ASSETS 283,516 285,236
REGULATORY ASSETS 421,692 458,525
DEFERRED CHARGES 31,457 32,364
TOTAL $3,897,484 $3,928,337
See Notes to Consolidated Financial Statements.
December 31,
1996 1995
(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 731,272 731,102
Retained Earnings 269,071 235,107
Total Common Shareholder's Equity 1,056,927 1,022,793
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 21,977 52,000
Subject to Mandatory Redemption 135,000 135,000
Long-term Debt 1,042,104 1,034,048
TOTAL CAPITALIZATION 2,256,008 2,243,841
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 313,845 269,392
Other 174,903 184,103
TOTAL OTHER NONCURRENT LIABILITIES 488,748 453,495
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 6,053
Short-term Debt 43,500 89,975
Accounts Payable - General 31,015 37,744
Accounts Payable - Affiliated Companies 30,877 22,962
Taxes Accrued 65,400 71,696
Interest Accrued 15,281 16,158
Obligations Under Capital Leases 29,740 31,776
Other 66,436 74,463
TOTAL CURRENT LIABILITIES 282,249 350,827
DEFERRED INCOME TAXES 594,879 612,147
DEFERRED INVESTMENT TAX CREDITS 146,473 155,202
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 96,125 99,832
DEFERRED CREDITS 33,002 12,993
COMMITMENTS AND CONTINGENCIES (Note 3)
TOTAL $3,897,484 $3,928,337
Consolidated Statements of Retained Earnings
Year Ended December 31,
1996 1995 1994
(in thousands)
Retained Earnings January 1 $235,107 $216,658 $177,638
Net Income 157,153 141,092 157,502
392,260 357,750 335,140
Deductions:
Cash Dividends Declared:
Common Stock 112,508 110,852 106,608
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 2,360
6-1/4% Series 1,875 1,875 1,875
6.30% Series 2,205 2,205 1,978
6-7/8% Series 2,063 2,063 2,063
7.08% Series 531 2,124 2,124
7.76% Series - - 317
Total Cash Dividends Declared 122,475 122,412 118,258
Capital Stock Expense 714 231 224
Total Deductions 123,189 122,643 118,482
Retained Earnings December 31 $269,071 $235,107 $216,658
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 542,000 retail customers
in its service territory of northern and eastern Indiana and a portion of
southwestern Michigan. Wholesale electric power is supplied to neighboring
utility systems, power marketers and the American Electric Power (AEP) System
Power Pool (Power Pool). As a member of the 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 Commis-
sion (MPSC). The Federal Energy Regulatory Commission (FERC) regulates
wholesale rates.
Principles of Consolidation
The consolidated financial statements include I&M and its wholly-owned
subsidiaries. Significant intercompany items are eliminated in consolidation.
Basis of Accounting
As a cost-based rate-regulated entity, I&M's financial statements reflect
the actions of regulators that result in the recognition of revenues and
expenses in different time periods than enterprises that are not cost-based
rate-regulated. In accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory liabilities
(deferred income) are recorded to reflect the economic effects of regulation.
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 sal-vage, 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
depreciation and represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 1996, 1995
and 1994 were not significant.
Depreciation and Amortization
Depreciation of electric utility plant is provided on a straight-line
basis over the estimated useful lives of utility plant and is calculated
largely through the use of composite rates by functional class as follows:
Composite
Functional Class Depreciation
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, based on a twenty quarter rolling
average, the fuel clause mechanism provides for the refunding of the excess
earnings to ratepayers. Wholesale jurisdictional fuel cost changes are
expensed and billed as incurred.
Levelization of Nuclear Refueling Outage Costs
Incremental operation and maintenance costs associated with refueling
outages at the Donald C. Cook Nuclear Plant (Cook Plant) are deferred
commensurate with their rate-making treatment and amortized over the period
(generally eighteen months) beginning with the commencement of an outage and
ending with the beginning of the next outage.
Income Taxes
The Company follows the liability method of accounting for income taxes as
prescribed by SFAS 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. Deferred investment tax
credits, which represent a regulatory liability, are being amortized over the
life of the related plant investment commensurate with recovery in rates.
The Company's policy with regard to investment tax credits for nonutility
property is to practice the flow-through method of accounting.
Debt and Preferred Stock
Gains and losses on 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 is credited to paid-in capital and amortized to
retained earnings.
Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds
Securities held in trust funds for decommissioning nuclear facilities and
for the disposal of spent nuclear fuel are recorded at market value in
accordance with SFAS 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.
2. EFFECTS OF REGULATION AND PHASE-IN
PLANS:
In accordance with SFAS 71 the consolidated financial statements include
assets (deferred expenses) and liabilities (deferred income) recorded in
accordance with regulatory actions to match expenses and revenues in
cost-based rates. Regulatory assets are expected to be recovered in future
periods through the rate-making process and the regulatory liabilities are
expected to reduce future cost recoveries. Among other things , application
of SFAS 71 requires that the Company's rates be cost-based regulated. The
Company has reviewed all the evidence currently available and concluded that
it continues to meet the requirements to apply SFAS 71. In the event a
portion of the Company's business were to no longer meet those requirements
net regulatory assets would have to be written off for that portion of the
business and assets would have to be tested for possible impairment.
Regulatory assets and liabilities are comprised of the following:
December 31,
1996 1995
(in thousands)
Regulatory Assets:
Amounts Due From Customers for
Future Income Taxes $317,059 $309,640
Department of Energy
Decontamination and
Decommissioning Assessment 45,994 48,862
Rate Phase-in Plan Deferrals 11,871 27,515
Nuclear Refueling
Outage Cost Levelization 15,805 23,467
Unamortized Loss On
Reacquired Debt 19,388 20,827
Other 11,575 28,214
Total Regulatory Assets $421,692 $458,525
Regulatory Liabilities:
Deferred Investment Tax Credits $146,473 $155,202
Other* 16 1,576
Total Regulatory Liabilities $146,489 $156,778
* Included in Deferred Credits on Consolidated Balance Sheets.
The Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.
I&M and AEP Generating Company (AEGCo), an affiliate, each own 50% of one
unit (Rockport 1) and each lease a 50% interest in the other unit (Rockport
2) from unaffiliated lessors under an operating lease. The gain on the sale
and leaseback of Rockport 2 was deferred and is being amortized, with related
taxes, over the initial lease term which expires in 2022.
Rate phase-in plans in the Company's Indiana and FERC jurisdictions 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 $11.9 million and $27.5 million at December 31, 1996 and
1995, respectively. Amortization was $15.6 million in 1996, 1995 and 1994.
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 1997-1999 are estimated to be $340
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
The Company is involved in a number of legal proceedings and claims.
While management is unable to predict the ultimate outcome of litigation, it
is not expected that the resolution of these matters will have a material
adverse effect on the results of operations or financial condition.
Nuclear Plant
I&M owns and operates the two-unit 2,110 mw Donald C. Cook Nuclear Plant
under licenses granted by the Nuclear Regulatory Commission. The operation
of a nuclear facility involves special risks, potential liabilities, and
specific regulatory and safety requirements. Should a nuclear incident occur
at any nuclear power plant facility in the United States, the resultant
liability could be substantial. By agreement I&M is partially liable
together with all other electric utility companies that own nuclear generating
units for a nuclear power plant incident. In the event nuclear losses or
liabilities are underinsured or exceed accumulated funds and recovery is not
possible, results of operations and financial condition would be negatively
affected.
Nuclear 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 $35.8 million annually under these policies.
Spent Nuclear Fuel Disposal
Federal law provides for government responsibility for permanent spent
nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel
disposal. A fee of one mill per kilowatthour for fuel consumed after April
6, 1983 is being collected from customers and remitted to the U.S. Treasury.
Fees and related interest of $172 million for fuel consumed prior to April 7,
1983 have been recorded as long-term debt. I&M has not paid the government
the pre-April 1983 fees due to continued delays and uncertainties related to
the federal disposal program. At December 31, 1996, funds collected from
customers towards the pre-April 1983 fee and related earnings thereon
approximate the liability.
Decommissioning and Low Level Waste Accumulation Disposal
Decommissioning costs are accrued over the service life of the Cook
Plant. The licenses to operate the two nuclear units expire in 2014 and
2017. After expiration of the licenses the plant is expected to be
decommissioned through dismantlement. 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. This in turn depends on future developments in the
federal government's spent nuclear fuel disposal program. Continued delays
in the federal fuel disposal program can result in increased decommissioning
costs. The Company is recovering estimated decommissioning costs in its
three rate-making jurisdictions based on at least the lower end of the range
in the most recent decommissioning study at the time of the last rate
proceeding. The Company records decommissioning costs in other operation
expense and records a noncurrent liability equal to the decommissioning cost
recovered in rates; such amount was $27 million in 1996, $30 million in 1995
including $4 million of special deposits and $26 million in 1994. Decom-
missioning costs recovered from customers are deposited in external trusts.
Trust fund earnings increase the fund assets and the recorded liability and
decrease the amount needed to be recovered from ratepayers. At December 31,
1996 the Company has recognized a decommissioning liability of $314 million
which is included in other noncurrent liabilities.
4. RELATED PARTY TRANSACTIONS:
Benefits and costs of the AEP System's generating plants are shared by
members of the Power Pool. Under the terms of the AEP System Interconnection
Agreement, capacity charges and credits are designed to allocate the cost of
the AEP System's capacity among the Power Pool members based on their
relative peak demands and generating reserves. Power Pool members are also
compensated for the out-of-pocket costs of energy delivered to the Power Pool
and charged for energy received from the Power Pool. The Company is a net
supplier to the pool and, therefore, receives capacity credits from the Power
Pool.
Operating revenues include revenues for capacity and energy supplied to
the Power Pool as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Capacity Revenues $ 57,594 $ 59,918 $ 88,183
Energy Revenues 98,162 83,799 52,274
Total $155,756 $143,717 $140,457
Purchased power expense includes charges of $34.5 million in 1996, $25.4
million in 1995 and $33.1 million in 1994 for energy received from the Power
Pool.
Power Pool members share in wholesale sales to unaffiliated entities
made by the Power Pool. The Company's share of the wholesale power pool
sales included in operating revenues were $73.4 million in 1996, $52.6
million in 1995 and $54.1 million in 1994.
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 $8.1
million in 1996, $10.7 million in 1995 and $14.2 million in 1994. 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 $85.4 million, $85.2 million and $82.4 million in 1996, 1995
and 1994, respectively.
The cost of power purchased from Ohio Valley Electric Corporation, an
affiliated but non-associated Company that is not a member of the Power
Pool, was included in purchased power expense in the amounts of $10.7
million, $4.0 million and $.9 million in 1996, 1995 and 1994, 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 owner-ship in proportion
to the AEP System companies' respective peak demands. Pursuant to the terms
of the agreement, other operation expense includes equalization credits of
$46.3 million, $46.7 million and $50.3 million in 1996, 1995 and 1994,
respectively.
Revenues from providing barging services were recorded in nonoperating
income as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Affiliated Companies $22,740 $23,160 $24,001
Unaffiliated Companies 6,776 6,992 5,021
Total $29,516 $30,152 $29,022
American Electric Power Service Corporation (AEPSC) provides certain
managerial and professional services to AEP System companies. The costs of
the services are billed by AEPSC on a direct-charge basis to the extent
practicable and on reasonable bases of proration for indirect costs. The
charges for services are made at cost and include no compensation for the use
of equity capital, which is furnished to AEPSC by AEP Co., Inc. Billings
from AEPSC are capitalized or expensed depending on the nature of the
services rendered. AEPSC and its billings are subject to the regulation of
the SEC under the 1935 Act.
5. BENEFIT PLANS:
The Company and its subsidiaries participate in the AEP System pension
plan, a trusteed, noncontributory defined benefit plan covering all employees
meeting eligibility requirements. Benefits are based on service years and
compensation levels. Pension costs are allocated by first charging each
System company with its service cost and then allocating the remaining
pension cost in proportion to its share of the projected benefit obligation.
The funding policy is to make annual trust fund contributions equal to the
net periodic pension cost up to the maximum amount deductible for federal
income taxes, but not less than the minimum required contribution in
accordance with the Employee Retirement Income Security Act of 1974. Net
pension costs for the years ended December 31, 1996, 1995 and 1994 were $4.1
million, $2.7 million and $5 million, respectively.
An employee savings plan is offered which allows participants to
contribute up to 17% of their salaries into various investment alternatives,
including AEP Co., Inc. common stock. An employer matching contribution,
equaling one-half of the employees' contribution to the plan up to a maximum
of 3% of the employees' base salary, is invested in AEP Co., Inc. common
stock. The employer's annual contributions totaled $3.7 million in 1996 and
$3.9 million in 1995 and 1994.
Postretirement benefits other than pensions (OPEB) are provided for
retired employees under an AEP System plan. Substantially all employees are
eligible for postretirement health care and life insurance if they retire
from active service after reaching age 55 and have at least 10 service years.
The funding policy for OPEB cost is to make contributions to an external
Voluntary Employees Beneficiary Association trust fund equal to the
incremental OPEB costs (i.e., the amount that the total postretirement
benefits cost under SFAS 106, "Employers Accounting for Postretirement
Benefits Other Than Pensions," exceeds the pay-as-you-go amount).
Contributions were $8.4 million in 1996, $10.3 million in 1995, and $6.6
million in 1994. OPEB costs are determined by the application of AEP System
actuarial assumptions to each company's employee complement. The Company's
annual accrued costs for 1996, 1995 and 1994 required by SFAS 106 for
employees and retirees were $12.8 million, $13.6 million and $13.2 million,
respectively.
6. SUPPLEMENTARY INFORMATION:
Year Ended December 31,
1996 1995 1994
(in thousands)
Cash was paid for:
Interest (net of
capitalized amounts) $ 64,117 $71,457 $68,946
Income Taxes 125,707 88,675 85,854
Noncash Acquisitions
Under Capital
Leases were 48,305 32,073 92,199
In connection with the 1996 early termination of a western coal land
sublease the Company will receive cash payments from the lessee of $30.8
million over a ten year period which has been recorded at a net present value
of $22.8 million. In connection with the 1995 sale of western coal land and
equipment the Company will receive cash payments from the buyer of $31.5
million over a six year period which has been recorded at a net present value
of $26.9 million. In connection with construction of facilities in 1995 to
provide service to a new customer the Company will receive cash payments of
$21.4 million plus accrued interest over 20 years. The long-term portion of
these receivables is recorded as other property and investments and the
current portion is recorded as miscellaneous accounts receivable.
7. FEDERAL INCOME TAXES:
The details of federal income taxes as reported are as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Charged (Credited) to Operating Expenses (net):
Current $110,133 $ 75,686 $ 64,565
Deferred (24,730) (13,732) (18,057)
Deferred Investment Tax Credits (7,874) (7,929) (8,155)
Total 77,529 54,025 38,353
Charged (Credited) to Nonoperating Income (net):
Current 182 12,872 1,390
Deferred 43 (9,832) (1,718)
Deferred Investment Tax Credits (855) (1,075) (5,722)
Total (630) 1,965 (6,050)
Total Federal Income Taxes as Reported $ 76,899 $ 55,990 $ 32,303
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,
1996 1995 1994
(in thousands)
Net Income $157,153 $141,092 $157,502
Federal Income Taxes 76,899 55,990 32,303
Pre-tax Book Income $234,052 $197,082 $189,805
Federal Income Tax on Pre-tax Book Income at
Statutory Rate (35%) $81,918 $68,979 $ 66,432
Increase (Decrease) in Federal Income Tax
Resulting From the Following Items:
Depreciation 13,880 8,954 (1,033)
Corporate Owned Life Insurance (2,178) (5,187) (4,521)
Nuclear Fuel Disposal Costs (3,096) (3,060) (4,498)
Investment Tax Credits (net) (8,729) (9,004) (13,875)
Other (4,896) (4,692) (10,202)
Total Federal Income Taxes as Reported $76,899 $55,990 $ 32,303
Effective Federal Income Tax Rate 32.9% 28.4% 17.0%
The following tables show the elements of the net deferred tax liability
and the significant temporary differences giving rise to such deferrals:
December 31,
1996 1995
(in thousands)
Deferred Tax Assets $ 241,842 $ 221,604
Deferred Tax Liabilities (836,721) (833,751)
Net Deferred Tax Liabilities $(594,879) $(612,147)
Property Related
Temporary Differences $(480,818) $(490,986)
Amounts Due From Customers
For Future Federal
Income Taxes (79,658) (83,277)
Deferred State Income Taxes (89,471) (71,712)
Deferred Net Gain -
Rockport Plant Unit 2 33,644 34,941
All Other (net) 21,424 (1,113)
Total Net Deferred
Tax Liabilities $(594,879) $(612,147)
The Company and its subsidiaries join in the filing of a consolidated
federal income tax return with their affiliates in the AEP System. The
allocation of the AEP System's current consolidated federal income tax to the
AEP System companies is in accordance with SEC rules under the 1935 Act.
These rules permit the allocation of the benefit of current tax losses to the
AEP System companies giving rise to them in determining their current tax
expense. The tax loss of the parent company, AEP Co., Inc., is allocated to
its subsidiaries with taxable income. With the exception of the loss of the
parent company, the method of allocation approximates a separate return
result for each company in the consolidated group.
The AEP System has settled with the 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. During the audit the IRS agents requested a ruling
from their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company for 1991 through
1993 should not be allowed. The COLI program was established in 1990 as part
of the Company's strategy to fund and reduce the cost of medical benefits for
retired employees. AEP filed a brief with the IRS National Office refuting
the agents' position. Although no adjustments have been proposed, a
disallowance of the COLI interest deductions through December 31, 1996 would
reduce earnings by approximately $51 million (including interest).
Management believes it will ultimately prevail on this issue and will
vigorously contest any adjustments that may be assessed. Accordingly, no
provision for this amount has been recorded. 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 of long-term tax-exempt municipal bonds and other
securities.
At December 31, 1996 and 1995 the fair values of trust investments were
$491 million and $434 million, respectively. Accumulated gross unrealized
holding gains were $22 million and $19.1 million and accumulated gross
unrealized holding losses were $1.2 million and $1 million at December 31,
1996 and 1995, respectively. The change in market value in 1996 was a net
unrealized holding gain of $2.6 million, in 1995 a net unrealized holding
gain of $24.9 million and in 1994 a net unrealized holding loss of $27.1
million.
The trust investments' cost basis by security type were:
December 31,
1996 1995
(in thousands)
Tax-Exempt Bonds $340,290 $336,073
Equity Securities 54,389 24,101
Treasury bonds 26,958 12,992
Corporate Bonds 7,977 1,971
Cash, Cash Equivalents
and Interest Accrued 40,430 40,356
Total $470,044 $415,493
Proceeds from sales and maturities of securities of $115.3 million
during 1996 resulted in $2.6 million of realized gains and $2.1 million of
realized losses. Proceeds from sales and maturities of securities of $78.2
million during 1995 resulted in $1.4 million of realized gains and $0.3
million of realized losses. During 1994 proceeds from sales and maturities
of securities of $20.1 million 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, 1996, the year of maturity of trust fund investments,
other than equity securities, was:
(in thousands)
1997 $ 56,452
1998-2001 120,327
2002-2006 163,250
After 2006 75,626
Total $415,655
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 $137 million and $140 million at
December 31, 1996 and 1995, respectively, and for long-term debt were $1.1
billion at each year end. The carrying amounts for preferred stock subject to
mandatory redemption were $135 million at each year end and for long-term
debt were $1.0 billion at December 31, 1996 and 1995. 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 estimated fair value.
9. LEASES:
Leases of property, plant and equipment are for periods of up to 35
years and require payments of related property taxes, maintenance and
operating costs. The majority of the leases have purchase or renewal options
and will be renewed or replaced by other leases.
Lease rentals for both operating and capital leases are generally
charged to operating expenses in accordance with rate-making treatment. The
components of rental costs are as follows:
Year Ended December 31,
1996 1995 1994
(in thousands)
Operating Leases $ 96,096 $ 96,472 $104,519
Amortization of
Capital Leases 55,789 45,843 30,875
Interest on
Capital Leases 10,624 9,987 7,643
Total Rental
Costs $162,509 $152,302 $143,037
Properties under capital leases and related obligations recorded on the
Consolidated Balance Sheets are as follows:
December 31,
1996 1995
(in thousands)
Electric Utility Plant:
Production $ 7,410 $ 9,346
Distribution 14,699 14,753
General:
Nuclear Fuel
(net of amortization) 59,681 69,442
Other 60,949 54,554
Total Electric Utility
Plant 142,739 148,095
Accumulated Amortization 28,598 24,933
Net Electric Utility
Plant 114,141 123,162
Other Property 19,035 22,361
Accumulated Amortization 2,211 3,017
Net Other Property 16,824 19,344
Net Properties under
Capital Leases $130,965 $142,506
Capital Lease Obligations:*
Noncurrent Liability $101,225 $110,730
Liability Due Within
One Year 29,740 31,776
Total Capital
Lease Obligations $130,965 $142,506
* Represents the present value of future minimum lease payments.
The noncurrent portion of capital lease obligations is included in other
noncurrent liabilities in the Consolidated Balance Sheets.
Properties under operating leases and related obligations are not
included in the Consolidated Balance Sheets.
Future minimum lease payments consisted of the following at December 31,
1996:
Non-
Cancelable
Capital Operating
Leases Leases
(in thousands)
1997 $ 14,685 $ 96,294
1998 12,474 91,397
1999 11,027 91,551
2000 9,848 91,403
2001 8,281 90,802
Later Years 36,371 1,749,187
Total Future Minimum
Lease Payments 92,686(a) $2,210,634
Less Estimated
Interest Element 21,402
Estimated Present
Value of Future
Minimum Lease
Payments 71,284
Unamortized Nuclear
Fuel 59,681
Total $130,965
(a) Excludes nuclear fuel rentals which are paid in proportion to heat
produced and carrying charges on the unamortized nuclear fuel balance. There
are no minimum lease payment requirements for leased nuclear fuel.
10. CUMULATIVE PREFERRED STOCK:
At December 31, 1996, 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 ac-
crued 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.
In January 1997 a tender offer for all series of preferred stock was
announced. In conjunction with the tender offer a special shareholders'
meeting was scheduled to be held on February 28, 1997 for the purpose of
considering amendments to the Company's articles of incorporation to remove
certain capitalization ratio requirements.
A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:
Call Price Shares Amount
December 31, Par Number of Shares Redeemed Outstanding December 31,
Series 1996 Value Year Ended December 31, December 31, 1996 1996 1995
1996 1995 1994 (in thousands)
4-1/8% $106.125 $100 233 - - 119,767 $ 11,977 $ 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% N/A 100 300,000 - - - - 30,000
$ 21,977 $ 52,000
B. Cumulative Preferred Stock Subject to Mandatory Redemption:
Shares Amount
Par Outstanding December 31.
Series(a) Value December 31, 1996 1996 1995
(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) 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) 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) 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) 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,
1996 1995
(in thousands)
First Mortgage Bonds $ 522,507 $ 562,017
Installment Purchase
Contracts 309,120 308,971
Other Long-term Debt (a) 171,706 163,060
Junior Subordinated
Deferrable Interest
Debentures (b) 38,771 -
Sinking Fund Debentures (c) - 6,053
1,042,104 1,040,101
Less Portion Due Within
One Year - 6,053
Total $1,042,104 $1,034,048
(a) Nuclear Fuel Disposal Costs including interest accrued. See Note 3.
(b) 8% - Due March 31, 2026 - $40,000,000 Outstanding less $1,228,500
discount.
(c) Called for redemption on March 1, 1996.
First mortgage bonds outstanding were as follows:
December 31,
1996 1995
(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
9.50 2021 - May 1 - 10,000
9.50 2021 - May 1 - 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) (2,493) (2,983)
Total $522,507 $562,017
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,
1996 1995
(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:
(a) 2014 - August 1 50,000 50,000
7.6 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (2,880) (3,029)
Total $309,120 $308,971
(a) The variable interest rate is determined weekly. The average weighted
interest rate was 3.5% for 1996 and 4.6% for 1995.
(b) The adjustable interest rate can be a daily, weekly, commercial paper or
term rate as designated by the Company. A weekly rate was selected which
ranged from 2.4% to 5.0% in 1996 and from 2.9% to 5% in 1995 and averaged
3.4% and 4.0% during 1996 and 1995, respectively.
Under the terms of certain installment purchase contracts, the Company is
required to pay amounts sufficient to enable the cities to pay interest on
and the principal (at stated maturities and upon mandatory redemption) of
related pollution control revenue bonds issued to finance the construction of
pollution control facilities at certain generating plants. On the two
variable rate series the principal is payable at the stated maturities or on
the demand of the bondholders at periodic interest adjustment dates which
occur weekly. The variable rate bonds due in 2014 are supported by a bank
letter of credit which expires in 2002. I&M has agreements that provide for
brokers to remarket the adjustable rate bonds due in 2025 tendered at
interest adjustment dates. In the event certain bonds cannot be remarketed,
I&M has a standby bond purchase agreement with a bank that provides for the
bank to purchase any bonds not remarketed. The purchase agreement expires in
2000. Accordingly, the variable and adjustable rate installment purchase
contracts have been classified for repayment purposes based on the expiration
dates of the standby purchase agreement and the letter of credit.
At December 31, 1996, future annual long-term debt payments, excluding
premium or discount, are as follows:
Principal Amount
(in thousands)
1998 $ 35,000
1999 35,000
2000 50,000
2001 40,000
Later Years 888,706
Total $1,048,706
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, 1996 and 1995 were available in the amounts of $409 million and
$372 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, 1996:
Note Payable $ 3,900 5.5%
Commercial Paper 39,600 7.2
Total $43,500 7.0
December 31, 1995:
Note Payable $52,200 6.1%
Commercial Paper 37,775 6.1
Total $89,975 6.1
12. COMMON SHAREHOLDER'S EQUITY:
Mortgage indentures, charter provisions and orders of regulatory
authorities place various restrictions on the use of retained earnings for
the payment of cash dividends on common stock. At December 31, 1996, $5.9
million of retained earnings were restricted. Regulatory approval is
required to pay dividends out of paid-in capital.
In 1996 and 1995 net changes in paid-in capital of $170,000 and
$(2,548,000), respectively, represented gains and expenses associated with
cumulative preferred stock transactions.
13. UNAUDITED QUARTERLY FINANCIAL INFORMATION:
Quarterly Periods Operating Operating Net
Ended Revenues Income Income
(in thousands)
1996
March 31 $329,883 $53,018 $35,767
June 30 323,494 50,430 33,507
September 30 339,847 61,123 44,546
December 31 335,269 55,846 43,333
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