ML17332A723

Forwards Indiana Michigan Power Co Annual Rept for 1994 & Projected Cash Flow for 1995,per 10CFR50.71(b) & 10CFR140.21(e)

ML17332A723
Person / Time
Site:	Cook
Issue date:	03/31/1995
From:	Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909K, AEP:NRC:909K, NUDOCS 9504070317
Download: ML17332A723 (43)

Text

P R.ICBM.I "EY'ACCELERATED RIDS PROCESSING REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9504070317 DOC.DATE: 95/03/31 NOTARIZED: NO DOCKET g FACIL:50-315 Donald C.

Cook Nuclear Power Plant, Unit 1, Indiana M

05000315 50-316 Donald C.

Cook Nuclear Power Plant, Unit 2, Indiana M

05000316 AUTH.NAME AUTHOR AFFILIATION P

FITZPATRICK,E.

Indiana Michigan Power Co. (formerly Indiana

& Michigan Ele RECIP.NAME RECIPIENT AFFILIATION Document Control Branch (Document Control Desk)

R

SUBJECT:

Forwards Indiana Michigan Power Co annual rept for 1994 S

, projected cash flow for 1995,per 10CFR50.71(b) 10CFR140.21(e).

DISTRIBUTION CODE M004D COPIES RECEIVED:LTR ENCL SIZE:

TITLE: 50.71(b)

Annual Financial Report NOTES 0

RECIPIENT ID CODE/NAME PD3-1 LA HIC INTE AL: FILE CENTER 0

EXTERNAL NRC PDR COPIES LTTR ENCL 1

1 1

1 1

1 1

1 RECIPIENT ID CODE/NAME PD3-1 PD COPIES LTTR ENCL 1

1 D

0 C'

N NOTE TOALL"RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTE! CONTACTTHE DOCUMENTCONTROL DESK, ROOM Pl-37 (EXT. 504-2083 ) TO ELIMINATEYOUR NAMEFROM DISTRIBUTIONLINISFOR DOCUMENTS YOU DON'T NEED!

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indiana Michigan Power Company P.O. Box 16631 Columbus, OH 43216 Narch 31, 1995 AEP:NRC:0909K Docket Nos,:

50-315 50-316 U.'S. Nuclear Regulatory Commission ATTN:

Document Control Desk Washington, D.

C.

20555 Gentlemen:

Donald C.

Cook Nuclear Plant Units 1 and 2

FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Attachment 1 contains the Indiana Michigan Power Company's (16M) annual report for 1994.

Attachment 2 contains a copy of 16M's projected cash flow for 1995.

These reports are submitted pursuant to 10 CFR 50.71(b) and 10 CFR 140.21(e).

Sincerely, E.

E. Fitzpa rick Vice President eh Attachments CC:

A. A. Blind G. Charnoff J.

B. Martin NFEM Section Chief NRC Resident Inspector

- Bridgman J.

R. Padgett 95040703i7 95033i PDR ADOCK 050003i5 PDR

ATTACHMENT 1 TO AEP:NRC:0909K INDIANAMICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1994

1994 Annual Report

CONTENTS

Background

Directors and Officers

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~ 2 Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations and Financial Condition..........

4-9 Independent Auditors'eport 10 Consolidated Statements of Income Consolidated Balance Sheets..............

12-13 Consolidated Statements of Cash Flows

. 14 Consolidated Statements of Retained Earnings..

. 15 Notes to Consolidated Financial Statements 16-28 Operating Statistics

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Dividends and Price Ranges of Cumulative Preferred Stock 31-32

NA MICHIGANPOWER COMPANY AND SUBSIDIARIES One Summit Square, p.O. Box 60, Fort Wayne, indiana 46801 BACKGROUND INDIANAMICHIGANPOWER COMPANY(the Company) is engaged in the generation, purchase, transmission and distribution of electric power.

The Company serves approximately 531,000 retail customers in northern and eastern Indiana and a portion of southwestern Michigan and sells and transmits power at wholesale to other electric utilities, municipalities and electric cooperatives.

Approximately 82% of the Company's retail sales are in Indiana and 18% in Michigan. The principal industries served are primary metals, transportation equipment, fabricated metal products, electrical and electronic machinery, rubber and miscellaneous plastic products and chemicals and allied products.

The Company is a subsidiary of American Electric Power Company, Inc., and was organized under the laws of Indiana on February 21, 1925. The Company's two wholly-owned subsidiaries, Blackhawk Coal Company and Price River Coal Company, were formerly engaged in coal-mining operations in Utah.

Blackhawk Coal Company currently leases or subleases portions of its coal rights, land and related mining equipment to unaffiliated companies.

In addition, the Company has a river transportation division (RTD) that barges coal on the Ohio and Kanawha Rivers to AEP System generating Plants. The RTD also provides some barging services to unaffiliated companies.

The Company owns and leases 4,434 megawatts (mw) of generating capacity which includes 2,295 mw of coal-fired generation and the 2,110 mw Donald C. Cook Nuclear Plant.

The generating plants and transmission facilities of the Company and certain other affiliated AEP System utilitysubsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission Agreement.

Wholesale energy sales made by the Power Pool are allocated to the Pool members.

The other AEP System Pool members are: Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company and Ohio Power Company.

The Company is also directly interconnected with its affiliate, AEP Generating

Company, and the following unaffiliated entities:

Central Illinois Public Service

Company, The Cincinnati Gas 5 Electric Company, Commonwealth Edison Company, Consumers Power Company, Illinois Power Company, Indianapolis Power 5. Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power and Light Company, as well as Indiana-Kentucky Electric Corporation (a subsidiary of Ohio Valley Electric Corporation, an affiliate that is not a member of the AEP System)

~ In addition, the Company is interconnected through the AEP System with two other affiliated companies, Kingsport Power Company and Wheeling Power Company and with numerous unaffiliated utilities.

DIRECTORS Mark A. Bailey Peter J. DeMaria William N. D'Onofrio A. Joseph Dowd (a)

E. Linn Draper, Jr.

William J

~ Lhota Gerald P. Maloney OFFICERS James J. Markowsky (b)

Richard C. Mange Albert H. Potter (c)

Ronald E. Prater (d)

David B. Synowiec (d)

Dale M. Trenary (c)

William E. Walters E. Linn Draper Jr.

Chairman of the Board and Chief Executive Officer Gerald P. Maloney Vice President Richard C. Menge President and Chief Operating Officer James J. Markowsky Vice President Mark A. Bailey Vice President John F. DiLorenzo, Jr.

Secretary A. Alan Blind (e)

Site Vice President, Donald C. Cook Nuclear Plant Elio Bafile Assistant Secretary and Assistant Treasurer Peter J. DeMaria Vice President and Treasurer Jeffrey D. Cross Assistant Secretary William N. D'Onofrio Vice President Carl J. Moos Assistant Secretary A. Joseph Dowd (a)

Vice President John B. Shinnock Assistant Secretary Eugene E. Fitzpatrick Vice President Leonard V. Assante Assistant Treasurer William J. Lhota Vice President Bruce M. Barber Assistant Treasurer Gerald R. Knorr Assistant Treasurer As ofJanuary 1, 1995 the cttrrent directors and officer ofIndiana Michigan Power Company were employees ol'American Electric power Service Corporation with nine exceptions: Messrs. Bafile, Bailey, Blind, D'Onofrio, Mange, Moos, Potter, Trenary and Wo(ters, who were employees of Indiana Michigan Power Company.

(el Ree/oned Notrernber 9O, 1994 (bl Elected Jenrery 24, 1995 (cl Elected Afrri728, 1994 (dl Reejtned Aprg 26, 1994 (el Elected htey 1, 1994

IINDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data INCOME STATEMENTS DATA:

1 94 Year En D

m 1992 (in thousands) ef 1

1 91 Operating Revenues Operating Expenses Operating Income Nonoperating Income (Loss)

Income Before Interest Charges Interest Charges Net Income Preferred Stock Dividend Requirements Earnings Applicable to Common Stock

$ 1,251,309

$ 1,202,643

$ 1,196,755

$ 1,225,867

~12~7

~272

~10

~12

~9578

$ 1,271,514 1 $77) ~2 4

145 821 4

115 088

~108 531 4

121 515 S

102 804 221,731 209,920 195,520 227,289 201,491

~742 ~24) ~14 11

~721 ~77 229,159 209,686 209,635 223,568 209,048

~SJiSZ ~t56K ~KSBZ 157,471 129,313 123,948

'36,932 118,391 lllSSf ~14 22 15 417 ~1417 ~17 BALANCESHEETS DATA:

19 4 199 December 1

1992 (in thousands) 1991

~190 Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant Regulatory Assets

$4,269,306

~1~4 42 609 366 4

481 212

$4,290,957

~1714 29

~2576 128 441 681

$4,266,480

~1~14

~2635 042 208 938

$4,135,820

~12~14 42 614 471 4

141 517

$4,066,227 1 421 2 5

2 644 942 164 739 Total Assets 43 915 729 43 765 458 43 645 798 43 481 878 43 501 925 Common Stock and Paid-in Capital Retained Earnings Total Common Shareowner's Equity 791,095 21f165Q Sl 007 753 791,517

~177 38 4

969 155 782,741 17~1 4

954 050 782,741 fff9 243 4

951 984 782,741

~1~4 4

933 149 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption Subject to Mandatory Redemption (a)

Total Cumulative Preferred Stock 52,000 S

87,000

~1~00 10~0 197,000 S

197,000 S

197,000 4

187 000 197 000

~187 000 4

197 000

~$

197 00 Long-term Debt (a)

Obligations Under Capital Leases (a)

Total Capitalization and Liabilities lel Including portion due within one yeer.

4 152 589 4

98 753 126 689 102 985 133 447 43 915 729

~3765 458

~3645 798 43 481 878

~3501 925

~1069 887

~1073 154 Sl 211 623 Sl 130 709 Sl 133 833

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIALCONDITION Results of Operations Net Income Increases Net income increased 21.8% to $ 157 million in 1994 mainly due to a retail base rate increase in the Company's Indiana jurisdiction, reduced interest expense due to the retirement of long-term debt, the adoption of Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109) in 1993 and the retirement of a gener-ating plant. The increase in net income in 1993 of 4.3% was the result of lower interest expense due to the retirement of long-term debt and the return to service of the Company's nuclear units from refueling and maintenance outages completed in 1992.

Operating Revenues Increase and Energy Sales Decline Operating revenues increased 4% in 1994 and a minor amount in 1993.

The changes in revenues can be analyzed as follows:

Increase (Decrease)

From Previous Year dollars in millions 1994 1993 Retail:

Price variance Volume variance 69.8 30.5 100.3 12.9

$ (75.1) 40.3

~34.8)

(4.3)

Mholesale:

Price variance Volume variance 90.7 J 142.7)

~52.0)()2.0)

Other Operating Revenues 0.4 Total

~40.7 4.0 (137.2) 172.7 35.5 9.6 5.2

~5.9 0.5 Retail operating revenues increased 13% during 1994 reflecting a $34.7 millionannual rate increase in the Indiana jurisdiction, increased decommis-sioning expense recoveries in the Michigan jurisdic-tion, the operation of the retail fuel and power supply cost recovery mechanisms and a 4% in-crease in energy sales.

The increase in retail energy sales in 1994 resulted from the growth in the number of customers served in all retail cus-tomer classes and increased usage by industrial and commercial customers.

Energy sales to residential customers remained constant in 1994 as mild weather during most of the year offset the effect of the severe weather in January and the unsea-sonably warm weather in May and June.

Although wholesale energy sales declined 35%

in 1994, wholesale revenues declined only 13%

reflecting the continuing effect of fixed capacity charges recovered from the AEP System Power Pool (Power Pool), which are unrelated to the amount of energy actually delivered, and an increase in take-or-pay capacity reservation charges collected from unaffiliated utilities. The decline in wholesale energy sales reflects the decrease in energy available for delivery to the Power Pool due to the scheduled refueling and maintenance outag-es at both of the Company's 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.

Although retail energy sales increased 5% in 1993, retail revenues decreased 4% reflecting the operation of fuel and power supply recovery mech-anisms due to the increased availability in 1993 of the lower cost nuclear units.

Under the retail juris-dictional fuel clauses, revenues were accrued in 1992 for future recovery of higher cost replace-ment power during the nuclear outages.

In 1993, with the nuclear units returned to full service, the accruals for higher cost coal based replacement power ceased.

The increase in retail energy sales in 1993 reflects continued growth in industrial customer

usage, a return to normal weather and growth in the number of customers in all retail classes.

Wholesale revenues increased 10% and whole-sale energy sales increased 47%

in 1993 due primarily to the increased availability of the nuclear generating capacity making more energy available for sale to the Power Pool and increased sales by the Power Pool to unaffiliated utilities which the Company shares as a member of the Pool.

IIVDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Operating Expenses Increase Changes in the components of operating ex-penses were as follows:

Increase (Decrease)

From Previous Year dollars in millions 1994 1993 Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization (2.6) (1.8) 5.4 4.1 Amortization of Rockport Plant Unit 1 Phase-in Plan Oeferrals (0.7)

(4.0)

Taxes Other Than Federal Income Taxes 3.3 4.8 5.7 9.2 Federal Income Taxes 6.4 18.4 9.2 36.1 Total

~36.9 3.7

~8.5)

(0.9)

Fuel expense declined in 1994 due to a signifi-cant reduction in nuclear generation, partially offset by a 6% increase in fossil generation.

Nuclear gen-eration declined by 43%

due to the scheduled refueling outages at both nuclear units.

The in-crease in 1993 fuel expense was mainly attribut-able to a significant increase in nuclear generation and increased fossil generation, partially offset by a decrease in the average cost of fuel.

Refueling and maintenance outages in 1992 coupled with the absence of outages in 1993 accounted for the increase in nuclear generation.

The increase in purchased power expense in 1994 reflects increased energy receipts from the Power Pool to replace the nuclear power that was not available due to the scheduled nuclear refueling and maintenance outages in 1994 and increased purchases from unaffiliated utilities for immediate resale to other unaffiliated utilities.

Purchased power expense declined in 1993 due to reduced energy receipts from the Power Pool because of the increased availability of both nuclear units and decreased purchases from AEP Generating Compa-ny (AEGCo), an affiliate that is not a member of the Power Pool.

In 1993 energy purchased from AEGCo was reduced since both of AEGCo's gener-ating units had outages for planned boiler main-tenance and repairs.

Other operation expense increased in 1994 due to regulator approved increases in accruals of additional nuclear decommissioning expense and other postretirement benefits commensurate with rate recovery and the accrual of employee sever-ance benefits resulting from the closing of the Breed Plant and the recommendations from an organizational review study.

The 1993 increase also reflected increased nuclear costs including decommissioning accruals and other postretirement benefit accruals.

The increase in taxes other than federal income taxes in 1993 was primarily due to a substantial increase in Indiana supplemental net income tax.

In 1992 Indiana supplemental net income tax was significantly reduced by the deduction of nuclear refueling and maintenance outage costs.

There were no refueling outages in 1993.

Federal income taxes attributable to operations increased in both periods due to increased pre-tax operating income.

Nonoperating Income increases and Financing Costs Decline Nonoperating income increased in 1994 reflect-ing the favorable tax effect of the Breed Plant closing and the effect of the recordation in 1993 of the unfavorable effect of adopting SFAS 109 for nonutility assets and liabilities.

The decline in nonoperating income in 1993 was due to the adoption of the new tax accounting standard, the effect of interest income recorded in 1992 from the settlement of prior years'ederal income tax audits and the reversal in 1992 of a previously recorded provision for a loss as a result of the successful settlement of a coal royalty dispute in the state of Utah.

Interest charges declined in both 1994 and 1993 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.

During 1993

$ 142 million of long-term bonds were retired and

$ 150 million of bonds and

$ 97 million of installment purchase contracts were refinanced at lower rates.

Construction Spending Gross plant and property additions were

$ 212 million in 1994 and $ 125 million in 1993.

Manage-ment estimates construction expenditures for the next three years to be

$393 million including expenditures necessary to meet the requirements of the Clean Air Act Amendments of 1990.

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 and investments in common equity by the Company's parent, Ameri-can Electric Power Co.,

Inc.

(AEP Co.,

Inc.).

However, all of the construction expenditures for the next three years are expected to be financed internally.

These estimated construction expendi-tures do not include any major new generating capacity.

Capital Resources When necessary the Company generally issues short-term debt to provide for interim financing of capital expenditures that exceed internally generat-ed funds.

At December 31, 1994, unused short-term lines of credit shared with other AEP System companies of $558 million were available.

A charter provision limits the Company's short-term borrowings to $ 130 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 recently received regulatory approval to issue up to $ 160 million of long-term debt.

Management expects to use the proceeds to retire short-term debt, to refinance higher cost and maturing long-term debt and to reacquire cumula-tive preferred stock.

The Company presently exceeds all minimum coverage requirements for issuance of preferred stock and long-term debt. At December 31, 1994, long-term debt and preferred stock coverage ratios were 5.08 and 2.74, respectively.

Competition In exchange for the exclusive right to provide electric generation, transmission and distribution services within a designated service territory at cost-based regulated prices that provide the oppor-tunity to earn a regulator-determined reasonable rate of return on shareholders'quity, electric utilities are obligated to serve all customers within such service territories.

While the Company is a regulated monopoly, we have competed historically with self-generation and with distributors of alter-native sources of energy, such as natural gas, fuel oil and coal, within our service area.

In recent years regulated electric utilities have also competed with independent power producers for the right to build and operate new generating plant.

The primary competitive factors have been

price, reliability of service and the ability of customers to utilize sources of energy other than electric power.

The lack of independent power producers and significant self generation in our service territory evidences our past ability to compete.

With re-spect to alternative energy sources, management believes that the convenience and versatility of electricity and reliability of our service coupled with the limited ability of customers to substitute other energy sources for electric power have placed us in a favorable competitive position.

However, we continue to work to improve the competitiveness, effectiveness and reliability of our product.

The

Company, for example, markets high-efficiency heat pumps and off-peak storage water heaters which make electricity competitive with natural gas for space and water heating.

Competition in the wholesale market, that is the sale of bulk power to other public and municipal utilities, is not new and has been increasing for a number of years.

This is particularly true in the short-teim market.

The National Energy Policy Act of 1992 (the Energy Act) facilitated competition in the short and long-term wholesale market since, among other

things, it authorized the Federal Energy Regulatory Commission (FERC) to order transmission access for wholesale transactions.

The principal factors in competing for wholesale sales are price including fuel costs, availability of

capacity, transmission capability and

cost, and reliability of service.

Management believes that over the years the Company has generally main-tained a favorable competitive position in these factors.

However, due to the recent availability of additional capacity of other utilities and reduced fuel prices, price competition, particularly in the short-term wholesale

market, has

been, and is expected to be important in the future.

With the passage of the Energy Act, the poten-tial for retail wheeling, i.e., competition for retail sales, is getting considerable attention.

While the Energy Act gave the FERC broad authority to mandate transmission access in the wholesale market, it prohibits the FERC from ordering retail wheeling. A number of state legislatures and state regulatory agencies have begun to study retail wheeling with encouragement from major industrial customers.

If it occurs, increased competition may require the resolution of some complex issues, such as

I stranded investment and the obligation to serve.

When a customer leaves a utilitysystem there is an issue of who pays for regulatory

assets, plant investment and commitments that are no longer needed.

If a customer leaves its native electric supplier and later decides to return, the issue of whether the original local utilityhas an obligation to serve the returning customer must also be ad-dressed.

If not recovered directly from customers that choose another supplier and/or from the remaining regulated customers, the Company, like all electric utilities, will be required to address stranded investment losses that could result from any future loss of customers or reduced pricing from head-to-head competition.

Management intends to seek recovery of any stranded invest-ment, including regulatory assets, as an appropriate recovery of previously approved cost of service.

Activity-based budgeting and cost management techniques are being currently developed to enable management to cost logical work activities and services.

By examining our operations by logical work units, the cost of all major activities can be better controlled, identified and evaluated to prop-erly price our products and to eliminate unneces-sary activities and their cost. Management believes these activities willenhance our ability to compete.

The development of tools and training to enable management to better manage the costs of opera-tions are only one of the options currently being pursued.

In 1994 the Company's management team has been:

Reviewing and streamlining operations and

staffing, o Reducing layers of supervision, Expanding customer relations and service activities, o Expanding its ability to help customers adopt new electro-technologies to reduce their usage of electricity, and Expanding strategic planning and manage-ment training activities.

Management is committed to maintaining and enhancing our business.

Management is moving in "new directions" to maintain and improve our competitive position.

Whether competition ex-pands or not, these efforts should serve to lower cost of service and rates and improve sales through economic development in our service territory.

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Environmental Concerns Clean AirAct The Clean Air Act Amendments of 1990 (CAAA) require, among other things, substantial reductions in sulfur dioxide and nitrogen oxide emissions from electric generating plants. The first phase of reductions in sulfur dioxide emissions (Phase I) began on January 1, 1995 and the sec-ond, more restrictive phase (Phase II) begins on January 1, 2000.

The law also establishes a

permanent nationwide cap on sulfur dioxide emis-sions after 1999.

Two of the Company's generating units, Tan-ners Creek Unit 4 and the Breed Plant, were affect-ed by the first phase of the CAAA. Tanners Creek Unit 4 complied by fuel switching with minimal capital cost.

Management decided to close the 325 megawatt Breed Plant in 1994, due to its

design, age and the cost of complying with the CAAA.

The closing of the Breed Plant did not adversely affect results of operations.

Phase II of the CAAAwillrequire further compli-ance actions and additional costs.

Management intends to seek timely recovery of all CAAAcosts.

Global Climate Change Concern about global climate change, or "the greenhouse effect" has been the focus of intensive debate within the United States and around the world. Much of the uncertainty about what effects greenhouse gas concentrations will have on the global climate results from a myriad of factors that affect climate.

Based on the terms of a 1992 United Nations treaty that pledged the United States to reduce greenhouse gas emissions, the Clinton Administration developed a voluntary plan to reduce greenhouse gas emissions to 1990 levels by the year 2000.

As part of this plan, the AEP System is participating with the U.S. Department of Energy (DOE) and other electric utilitycompanies in a climate change program to limit future green-house gas emissions.

The climate change program applies a policy of proactive environmental stewardship, whereby actions are taken that make economic and environ-mental sense on their own merits, irrespective of the uncertain threat of global climate change.

The plan includes energy conservation

programs, improvements in fossil generation efficiency, increased use of nuclear capacity and forest man-

agement activities.

However, should it be deter-mined necessary to enact significant new measures to control the burning of coal, the cost of such measures if not recovered from ratepayers, could adversely impact results of operations and possibly financial condition.

EMF The potential for electric and magnetic fields (EMF) from transmission and distribution facilities, to adversely affect the public health is being exten-sively researched.

The AEP System continues to support research to help determine the extent, if any, to which EMF may adversely impact public health.

Our concern is that new laws imposing EMF limits may be passed or new regulations promulgated without sufficient scientific study and evidence to support them.

As long as there is uncertainty about EMF, the Company and other electric utilities will have difficulty finding accept-able sites for their facilities, which could hamper economic growth within our service area.

If the present energy delivery system must be changed because of EMF concerns, or ifthe courts conclude that EMF exposure harms individuals and that utilities are liable for damages, then the Company's results of operations and financial condition could be adversely

affected, unless the costs can be recovered from ratepayers.

Hazardous Material By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel.

In addition, generating plants and transmission and distribution facilities have used asbestos, polychlor-inated biphenyls (PCBs) and other hazardous and non-hazardous materials.

The Company is current-ly 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 (Superfund) ad-dresses clean-up of hazardous substance disposal sites and authorizes the United States Environmen-tal Protection Agency (Federal EPA) to administer the clean-up programs.

The Company has been named by the Federal EPA as a "potentially respon-sible party" (PRP) for eight sites and has received information requests for three other sites.

For four of the PRP sites, liability has been settled with no significant effect on results of operations.

18M also has been named as a PRP at one Illinois site and has received an information request for one Indiana site under similar state clean-up laws.

In all instances where the Company has been named a PRP or defendant, the disposal or recy-cling activity was in accordance with applicable laws and regulations.

However, Superfund does not recognize compliance as a defense, but impos-es strict liabilityon parties who fall within its broad statutory categories.

As a result, AEP has institut-ed a number of Systemwide policies that have raised the standard of care by going beyond regula-tory requirements where appropriate.

While the potential liabilityfor each site must be evaluated separately, several general statements can be made regarding such potential liability. The disposal. by the Company at a particular site is often unsubstantiated; the quantity of material disposed of at a site was generally small; and the nature of the material generally disposed of was non-hazardous.

Typically, the Company is one of many parties named PRPs for a site and, although liability is joint and several, at least some of the other parties are financially sound enterprises.

Therefore, present estimates do not anticipate material clean-up costs for identified disposal sites.

However, iffor unknown reasons, significant costs are incurred for cleanup, results of operations and possibly financial condition would be adversely affected unless the costs can by recovered from insurance proceeds and/or with regulatory approval from ratepayers.

Nuclear Cost The cost to operate and maintain the two-unit Donald C. Cook Nuclear Plant is impacted by Nu-clear Regulatory Commission (NRC) requirements and the normal aging of the plant (Unit 1 began commercial operation in 1975 and Unit 2 in 1978).

In addition, the cost to decommission the plant is affected by NRC regulations and the DOE's Spent Nuclear Fuel (SNF) disposal program.

Studies completed in 1994 estimate the cost to decommis-sion the plant and dispose of low level nuclear waste accumulation to range from $ 634 million to

$988 million in 1993 dollars.

By law the Company participates in the DOE's SNF disposal program which is described in Note 4 of the Notes to Con-solidated Financial Statements.

Decommissioning costs and spent nuclear fuel disposal costs are being recovered from ratepayers.

In 1993 the

II INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Indiana and the Michigan commissions approved higher levels of recovery so that the amount cur-rently being recovered is at least at the lower end of the range in the prior decommissioning study.

To date $212 million in decommissioning cost has been recovered and accrued.

Management intends to seek recovery through the rate-making process of changes in the estimate of decommissioning costs over the remaining plant life.

Nuclear operations are continually reviewed for ways to lessen the growth in operation, mainte-nance and decommissioning costs.

In 1994 Cook Plant achieved a superior rating from the Institute of Nuclear Power Operations, a nuclear industry oversight

group, and received improved NRC performance ratings.

Additionally, costs related to nuclear refueling outages at the Cook Plant have been reduced significantly in the last two years.

In 1994 the Financial Accounting Standards Board (FASB) added Accounting for Nuclear De-commissioning Liabilities to its agenda.

Among the topics to be studied by the FASB is the question of when future decommissioning liabilities should be recognized.

The Company and the electric utility industry accrue such costs over the service life of their nuclear facilities as recovered in rates.

A new requirement from the FASB could cause the annual provisions for decommissioning to increase should the estimate ofthe remaining unaccrued decommis-sioning costs be greater than the regulators'l-lowed recovery level.

Management believes that the industry's life of the plant accrual accounting method is appropriate and should be accepted by the FASB. Until the FASB completes its study and reaches a conclusion, the impact, if any, on results of operations and financial condition cannot be determined.

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 compa-nies that own nuclear generating units for a nuclear power plant incident.

Should nuclear losses or liabilities be underinsured or exceed accumulated funds, or should recovery through regulated rates be

denied, results of operations and financial condition would be negatively affected.

Specific information about nuclear risk management and potential liabilities is discussed in Note 4 of the Notes to Consolidated Financial Statements.

Litigation The Company is involved in a number of legal proceedings and claims.

While we are unable to predict the outcome of such litigation, it is not expected that the resolution of these matters will have a material adverse effect on financial condi-tion. Information about these matters can be found in the footnotes to the financial statements.

Effects of Inflation Inflation affects the cost of replacing utility plant and the cost of operating and maintaining such plant.

The rate-making process generally limits recovery to the historical cost of assets resulting in economic losses when inflation effects are not recovered from customers on a

timely basis.

However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.

INDEPENDENT AUDITORS'EPORT To the Shareowners and Board of Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP Columbus, Ohio February 21, 1995 10

Consolidated Statements of Income INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES 1994 Y

rEn dD emb r31 1993 (in thousands) 1 92 OPERATING REVENUES OPERATING EXPENSES:

Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses OPERATING INCOME NONOPERATING INCOME (LOSS)

INCOME BEFORE INTEREST CHARGES INTEREST CHARGES NET INCOME PREFERRED STOCK DIVIDENDREQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK

~12 ~10

~120~24

~11 ~7 201,739 131,234 293,024 139,423 136,244 220,206 108,274 264,543 142,637 138,794 193,830 180,365 251,897 137,787 133,365 15,644 71,191 41 079 15,644 67,918 34 7(47 16,303 62,189 2!~4 1 029 578 992 723

~1 1~2 221,731 7 428 209,920

~234 195,520 14 11 229,159 157,471 209,686 209,635

~873

~~7 129,313 123,948

~11 85 14 225

~14 7

~146 821 4

115 088

~108 531 See Notes to Consolidated Rnanoial Statements.

11

Consolidated Balance Sheets ASSETS De emb r 31 1 994 1 993 (in thousands)

ELECTRIC UTILITYPLANT:

Production Transmission Distribution General (including nuclear fuel)

Construction Work in Progress Total Electric UtilityPlant Accumulated Depreciation and Amortization NET ELECTRIC UTILITYPLANT

$2,602,527 839,198 608,752 1 52,470

~88 01

$2,494,834 849,920 644,720 204,909

~74 92 4,290,957 1 714 829 4,269,306

~159 40 2 609 366

~2 57 12 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 341 0 3 0671 OTHER PROPERTY AND INVESTMENTS 127 424 131 788 CURRENT ASSETS:

Cash and Cash Equivalents Accounts Receivable:

Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel - at average cost Materials and Supplies - at average cost Accrued UtilityRevenues Prepayments TOTAL CURRENT ASSETS 9,907 3,752 74,491 24,848 32,714 (121) 35,802 59,897 40,582 8 414 67,246 24,507 30,087 (504) 34,476 57,800 34,642

~12 04 286 534 264 049 REGULATORY ASSETS 4II1 212

~441 1

DEFERRED CHARGES

~71 4

~11 41 TOTAL

$ 3 915 729

$ 3 765 458 See Notes to Consolidoted Rnenciel Stotements.

12

IND MICHIGANPOWER COMPANY AND SUBSIDIARIES Dec mbr 1

CAPITALIZATIONAND LIABILITIES 94

~1 (in thousands)

CAPITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock:

Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION 56,584 734,511 21~$

1,007,763 62,000 135,000 929 887 2124 4

56,584 734,933 17~7 969,155 87,000 100,000

~107 1

4 2 22 309 OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning Other TOTAL OTHER NONCURRENT LIABILITIES 211,963 17i~4 169,706

~11 4

1

~2'~17 CURRENT LIABILITIES:

Long-term Debt Due Within One Year Short-term Debt - Commercial Paper Accounts Payable - General

'Accounts Payable - Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other TOTAL CURRENT LIABILITIES DEFERRED FEDERAL INCOME TAXES DEFERRED INVESTMENTTAX CREDITS DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS COMMITMENTSAND CONTINGENCIES (Note 4)

TOTAL 140,000 50,600 40,417 22,720 63,621 19,436 39,003

~7821 46,'~1 5tg 6~4 171~

~24~1

$3 915 729 50,075 40,437 17,481 54,473 18,894 20,585 7!~7 21 12 553 920

~18 i ttg2 211 446 1

242

$ 3 765 458 13

7 Consolidated Statements of Cash Flows Ye rEn D

em

~1 (in thousands)

OPERATING ACTIVITIES:

Net Income Adjustments for Noncash Items:

Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)

Deferred Federal Income Taxes Deferred Investment Tax Credits Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net)

Fuel, Materials and Supplies Accrued UtilityRevenues Accounts Payable Taxes Accrued Other (net)

Net Cash Flows From Operating Activities S 157,471 146,966 15,644 (18,779)

(17,049)

(13,877)

(10,596)

(3,423)

(5,940) 5,219 9,148

~11 444

~2I~4 S 129,313 148,270 15,644 33,827 (49,905)

(8,543) 13,102 14,938 43,913 8,233 38,644

~17 64

~71~72 S 123,948 141,453 16,303 (47,200) 29,897 (9,673)

(7,432) 1,018 (41,068)

(15,088) 4,514

~16 448 1

224 INVESTING ACTIVITIES:

Construction Expenditures Proceeds from Sales of Property and Other Net Cash Flows Used For Investing Activities (118,094)

~203 116 056 (108,867) 8

~10 482 (125,908)

~0

~125 00 FINANCING ACTIVITIES:

Capital Contributions from Parent Company Issuance of Cumulative Preferred Stock Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Change in Short-term Debt (net)

Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1

Cash and Cash Equivalents December 31 Soo hates to Consolidated Rnanoial Statements.

34,618 89,221 (35,798)

(101,833) 525 (106,608)

~112 4

1 ~29/

6,155

~752 4

9 907 10,000 98,776 243,426 (112,300)

(392,093) 5,875 (108,696)

~27 I~97)

(3,707)

~745 4

3752 271,722 (203,185)

(6,750)

(106,465)

~141 7

~Q 0K)

(4,8761

~123 5

7 459 14

I f~

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Retained Earnings January 1

Net Income Ye rEn e

D mber31 1991 (in thousands)

$ 177,638

$ 171,309

'I 57 471

~I2 13

'1~3~19

~30 22 1

92

$ 169,243

~12 94

~21 91 Deductions:

Cash Dividends Declared:

Common Stock Cumulative Preferred Stock:

4-1/8% Series 4.56%

Series 4.12%

Series 5.90%

Series 6-1/4% Series 6.30%

Series 6-7/8% Series 7.08%

Series 7.76%

Series 8.68%

Series

$2.15 Series

$2.25 Series Total Cash Dividends Declared Capital Stock Expense Total Deductions Retained Earnings December 31 106,608 495 273 165 2,360 1,875 1,978 2,063 2,124 317 118,258 193 11 451

$ 2'16 658 108,696 495 273 165 374 161 1,799 2,124 2,716 2,517 3,001 122,921 63 122 4

$ 177 638 106,465 495 273 165 2,124 2,716 2,604 3,440 2ZdK 121,882

~121 82

$ 171 309 See Notes to Consolidated Pinanoial Statements.

15

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

1. SIGNIFICANTACCOUNTING POLICIES:

Organization Indiana Michigan Power Company (the Company or IS.M) is a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a public utility holding company.

The Company is engaged in the generation, purchase, transmission and distribution of electric power in northern and eastern Indiana and a portion of southwestern Michigan.

As a member of the American Electric Power (AEP) System Power Pool (Power Pool) and a signatory company to the AEP Transmission Equalization Agreement, its facilities are operated in conjunction with the facilities of certain other AEP affiliated utilities as an integrated utility sys-tem.

Statement of Financial Accounting Standards (SFAS)

No. 71, Accounting for the Effects of Certain Types ofRegulation, regulatory assets and liabilities are recorded and represent regulator-approved deferred expenses or revenues, respec-tively, resulting from the rate-making process.

Such deferrals are amortized commensurate with their inclusion in rates (revenues).

UtilityPlant Electric utilityplant is stated at original cost and is generally subject to first mortgage liens.

Addi-

tions, 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 depreci-ation.

The Company has two wholly-owned subsidiar-ies, Blackhawk Coal Company and Price River Coal

Company, that were formerly engaged in coal-mining operations.

Blackhawk Coal Company cur-rently leases and subleases portions of its Utah coal rights, land and related mining equipment to unaffil-iated companies.

Price River Coal Company, which owns no land or mineral rights, is inactive.

Regulation As a member of the AEP System, IS.M is subject to regulation by the Securities and Exchange Com-mission (SEC) under the Public UtilityHolding Com-pany Act of 1935 (1935 Act).

Retail rates are regulated by the Indiana UtilityRegulatory Commis-sion (IURC) and the Michigan Public Service Com-mission (MPSC)

~

The Federal Energy Regulatory Commission (FERC) regulates wholesale rates.

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 (AFUDCj AFUDC is a noncash nonoperating income item that is recovered with regulator approval over the service life of utilityplant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects.

The average rates used to accrue AFUDC were Se0% in 1994, 8.75% in 1993 and 9.25% in'1992 and the amounts of AFUDC accrued were

$3.4

million,

$ 1.7 million and

$3.8 million in 1994, 1993 and 1992, respectively.

Depreciation and Amortization Principles of Consolidation The consolidated financial statements include I'M and its wholly-owned subsidiaries.

Significant intercompany items are eliminated in consolidation.

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:

Basis ofAccounting As a cost-based rate-regulated entity, IRM's financial statements reflect the actions of regula-tors that result in the recognition of revenues and expenses in different time periods than enterprises that are not rate regulated.

In accordance with Functional Class

~of Pro ere Production:

Steam-Nuclear Steam-Fossil-Fired Hydroelectric-Conventional Transmission Oistribution General Composite Annual Rates 3.4X 4.3X 3.0X 1.9X

4. 2/e 3.8X 16

i IIVDIAIVAMICHIGANPOWER COMPANY AND SUBSIDIARIES Amounts to be used for removal of non-nuclear plant are presently recovered through depreciation charges included in rates.

The accounting and rate-making treatment afforded nuclear decommis-sioning costs and nuclear fuel disposal costs are discussed in Note 4.

Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

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 invest-ment. The Company's policy with regard to invest-ment tax credits for non-utility property was to practice the flow-through method of accounting.

Debt and Preferred Stock Operating Revenues Revenues include the accrual of electricity con-sumed but unbilled at month-end as well as billed revenues.

Fuel Costs 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 reacquisi-tion costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates.

Fuel costs are matched with revenues in accor-dance 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 mecha-nism provides for the refunding of the excess earnings to ratepayers.

Wholesale jurisdictional fuel cost changes are expensed and billed as incurred.

Debt discount or premium and debt issuance expenses are amortized over the term of the related debt, with the amortization included in interest charges.

Redemption premiums paid to reacquire preferred stock are deferred and amortized in accordance with rate-making treatment.

The excess of par value over costs of preferred stock reacquired to meet sinking fund requirements is credited to paid-in capital.

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 until 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 liabilitymethod, 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

~

Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds Investments held in trust funds for decommis-sioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value effective January 1, 1994.

Previously such invest-ments were recorded at cost.

Adjustments for unrealized gains and losses to the carrying value of trust fund investments are not reflected in equity due to the rate-making process.

Instead the unreal-ized gains and losses are recorded as regulatory assets and liabilities.

Other Property and Investments Other property and investments are stated at cost.

17

8 6

Reclassifications

3. RATE MATTERS:

Certain prior-period amounts were reclassified to conform with current-period presentation.

Unaffiliated Coal and AffiliatedTransportation Cost Recovery

2. EFFECTS OF REGULATIONAND PHASE-IN PLANS:

The consolidated financial statements include assets and liabilities recorded in accordance with regulatory actions to match expenses and revenues in cost-based rates.

Regulatory assets are expect-ed to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future rate recoveries.

The Company's regulatory assets and liabilities are comprised of the following:

In October 1993, the FERC denied a request by a

wholesale customer seeking rehearing of a

February 1993 order.

The order concerned the reasonableness of coal costs from an unaffiliated supplier who leases a Utah mining operation from the Company and affiliated coal transportation charges.

The February order reversed an adminis-trative law judge's decision and dismissed the complaint.

The wholesale customer appealed the October order to the U.S. Court of Appeals.

It is not anticipated that the ultimate resolution of this matter will have a material adverse impact on results of operations.

Regulatory Assets:

Amounts Oue From Customers for Future Federal Income Taxes Department of Energy Decontamination and Decormissioning Assessment Rate Phase-in Plan Deferrals Nuclear Refueling Outage Cost Levelization Unamortized Loss On Reacquired Debt Other Total Regulatory Assets December 31 1994 1993 (in thousands)

$313,731

$286,948 51,896 43,159 32,151 18,472 21 803

~482 212 37,086 58,803 13,372 17,251 28 221

~aat 681 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 amortiza-tion through 1997 of prior-year deferrals.

Regulatory Liabilities:

Deferred Investment Tax Credits

$ 171,688

$ 186,032 Other Regulatory Liabilities*

350 158 Total Regulatory tiaallltlea

~272 038

~286 190

• Included in Deferred Credits on Consolidated Balance Sheets.

Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.

I(AM and AEP Generating Company (AEGCo), an affiliate, each own 50% of one unit (Rockport 1) and each lease a 50% inter-est 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.

4. COIVIIVIITMENTSAND 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 1995-1997 are estimated to be $393 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'eview and approval.

The contracts are for various terms, the longest of which extends to 2014, and contain various claus-es that would release the Company from its obliga-tion 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.

18

Litigation NDIANAMICHIGANPOWER COMPANY AND SIJBSIDIARIES Other Environmental Matters An appeal to the Indiana Court of Appeals by a local distribution utility of a 1992 DeKalb County Circuit Court of Indiana decision is pending.

Oral arguments before the Indiana Court of Appeals were held in January 1995.

The circuit court had dismissed the case filed under a provision of Indi-ana law that allows the local distribution utility to seek damages equal to the gross revenues received by the Company for rendering service in the desig-nated service territory of the local distribution utility. The Company had received approximately

$29 million in gross revenues from a major industri-al customer in the local distribution utility's service territory. The case resulted from a Supreme Court of Indiana decision which overruled an appeals court and voided an IURC order which assigned the major industrial customer to the Company.

The Company is involved in a number of other legal proceedings and claims.

While management is unable to predict the outcome of litigation, it is not expected that the resolution of these matters will have a material adverse effect on financial condition.

Clean AI'r The Clean AirAct Amendments of 1990 (CAAA) require significant reductions in sulfur dioxide and nitrogen oxide emissions from various AEP System generating plants.

The first phase of reductions in sulfur dioxide emissions (Phase I) began on January 1, 1995 and the second, more restrictive phase (Phase II) begins on January 1, 2000. The law also established a permanent nationwide cap on sulfur dioxide emissions after 1999.

The AEP Systemwide compliance plan calls for fuel switching to medium-sulfur coal at the Compa-ny's Tanners Creek Unit 4 with minimal capital cost.

The Breed unit which is a Phase I affected unit was closed in 1994.

The Company's other generating units are not affected in Phase I ~

The Company will incur additional costs to comply with Phase II requirements at its generating plants.

In addition, a portion of the costs of com-pliance for the AEP System may be incurred through the Power Pool (which is described in Note 8). Ifthe Company is unable to recover its compli-ance costs from its customers, results of opera-tions would be adversely impacted.

The Company and its subsidiaries are regulated by federal, state and local authorities with respect to air and water quality and other environmental matters.

Local authorities also regulate zoning.

The generation of electricity produces non-haz-ardous and hazardous by-products.

Asbestos, polychlorinated biphenyls (PCBs) and other hazard-ous materials have been used in the generating plants and transmission/distribution facilities.

Substantial costs to store and dispose of hazardous and non-hazardous materials have been incurred.

Significant additional costs could be incurred in the future to meet the requirements of new laws and regulations and to clean up disposal sites under existing legislation.

Management has no knowl-edge of any material clean up costs related to the Company's past disposal of hazardous and non-hazardous materials.

Nuclear Plant ISM 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 substantial.

By agree-ment ISM is partially liable together with all other electric utilitycompanies that own nuclear generat-ing units for a nuclear power plant incident. Should nuclear losses or liabilities be underinsured or exceed accumulated

funds, or should recovery through regulated rates be denied, results of opera-tions and financial condition would be negatively affected.

Specific information about nuclear risk management and potential liabilities is discussed below.

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 insur-ance 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 assess-ment of $79.3 million on each licensed reactor payable in annual installments of $ 10 million. As a result, IS.M could be assessed

$ 158.6 million per nuclear incident payable in annual installments of 19

$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 cover-age 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 $41.9 million under these policies.

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 de-commissioning liabilityequal to the decommission-ing cost recovered in rates which was $ 26 million in 1994,

$ 13 million in 1993 and

$ 12 million in 1992.

Decommissioning amounts recovered from customers are deposited in external trusts.

Trust fund earnings increase the fund assets and the recorded liability. Trust fund earnings decrease the amount to be recovered from ratepayers.

At December 31, 1994 the Company has recognized a decommissioning liabilityof $212 million.

Spent Nuclear Fuel Disposal Federal law provides for government responsibili-ty 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 $ 154 million for fuel consumed prior to April7, 1983 have been record-ed as long-term debt with an offsetting regulatory asset.

The regulatory asset at December 31, 1994 of $8.4 million is being amortized as rate recovery occurs.

IS.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, 1994, funds collected from customers and related earn-ings including accrued interest totaled

$ 145.6 million.

Decommissioning and Low Level Waste Accumula-tion 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 disman-tlement.

Estimated decommissioning and low level radioactive waste accumulation disposal costs range from $ 634 million to $ 988 million in 1993 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.

Decommis-sioning costs are being recovered in the three rate-

5. BENEFIT PLANS:

The Company and its subsidiaries participate in the AEP System pension plan, a trusteed, noncon-tributory 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 contri-butions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum contribution

'equired by the Employee Retirement Income Security Act of 1974.

Net pension costs for the years ended December 31, 1994, 1993 and 1992 were $ 5 million, $4.7 million and $ 5.6 million, respectively.

An employee savings plan is offered which allows participants to contribute up to 17% of their salaries into three investment alternatives, including AEP Co., Inc. common stock. An employer match-ing contribution, equaling one-half of the employees'ontribution to the plan up to a maxi-mum of 3% of the employees'ase

salary, is invested in AEP Co., Inc. common stock.

The employer's annual contributions totaled $3.9 million in 1994,

$3.5 million in 1993 and

$3.3 million in 1992.

Certain other benefits are provided for retired employees under an AEP System other postretire-ment benefit plan.

Substantially all employees are eligible for postretirement health care and life 20

II ~ ~

I NDIANAMICHIGANPOWER COIIIIPANY AND SUBSIDIARIES insurance ifthey have at least 10 service years and are age 55 at retirement.

Prior to 1993, net costs of these benefits were recognized as an expense when paid and totaled

$2.7 million in 1992.

SFAS

106, Employers'ccounting for Postretirement Benefits Other Than Pensions, was adopted in January 1993 for the Company's aggregate liabilityfor postretirement benefits other than pensions (OPEB) ~

SFAS 106 requires the accrual during the employee's service years of the present value liabilityfor OPEB costs.

Costs forthe accumulated postretirement benefits earned and not recognized at adoption are being recognized, in accordance with SFAS 106, as a transition obliga-tion over 20 years.

OPEB costs are determined by the application of AEP System actuarial assump-tions to each operating company's employee complement.

The annual accrued OPEB costs for employees and retirees required by SFAS 106, which includes the recognition of one-twentieth of the prior service transition obligation, were $ 13.2 million in 1994 and $ 12.4 million in 1993.

A Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB benefits was estab-lished and a corporate owned life insurance (COLI) program was implemented.

The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, as other property and investments.

For the Indiana jurisdiction where OPEB costs are reflected in cost of service, the amount contributed to the VEBA trust fund is the difference between the pay-as-you-go OPEB cost and the SFAS 106 total OPEB cost.

This contribution is funded by amounts collected from ratepayers plus net earnings from the COLI program.

For FERC and Michigan jurisdic-tions where recovery has not been approved and rates are insufficient to absorb these additional costs, the contribution to the VEBA trust fund is the cash generated by the COLI program.

Contri-butions to the VEBAtrust fund were $ 6.6 million in 1994 and $ 1.3 million in 1993.

6. SUPPLEMENTARY INFORMATION:

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 the increased OPEB costs which are not being currently recovered in rates.

Future recovery of the deferrals and the annual ongoing increased OPEB costs will be sought in the next base rate filings.

At December 31, 1994, $6.7 millionof incremental OPEB costs were deferred.

Year Ended December 31 1994 1993 1992 (in thousands)

$82,509 68,303

$84,691 15,285 Honcash Acquisitions Under Capital Leases were 92,199 15,467 47,905 Cash was paid for:

Interest (net of capitalized amounts)

$68,946 Income Taxes 85,854 21

~ 4

~

7. FEDERAL INCOME TAXES:

The details of federal income taxes as reported are as follows:

1994 Year Ended December 31 1993 (in thousands) 1992 Charged (Credited) to Operating Expenses (net):

Current Deferred Deferred Investment Tax Credits Total Charged (Credited) to Nonoperating Income (net):

Current Deferred Deferred Investment Tax Credits Total Total Federal Income Taxes as Reported

$ 64,565 (15,331)

~8) 55) 41 079 1,390 (1,718)

~5722)

~6060)

~35 029

$ 93,974 (50,959)

~8308) 34 707 6,026 1,054

~235) 6 845

~4) 552

$ 9,122 25,405

~9028) 25

~99 1,569 4,492

~645) 5 416

~30 915 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 Net Income Federal Income Taxes Pre-tax Book Income Federal Income Tax on Pre-tax Book Income at Statutory Rate (35% in 1994 and 1993; 34K in 1992)

Increase (Decrease) in Federal Income Tax Resulting From the Following Items:

Removal Costs Adoption of SFAS 109 Corporate Owned Life Insurance Nuclear Fuel Disposal Costs Investment Tax Credits (net)

Other Total Federal Income Taxes as Reported Effective Federal Income Tax Rate 1994

$ 157,471 35 029

~192 500

$ 67,375 (2,422)

(4,521)

(4,498)

(13,875)

~7030)

~35 029 18.2X 1993 (in thousands)

$ 129,313 41 552

~)70 865

$59,803 (2,632) 5,271 (4,697)

(2,432)

(8,543)

~52)8)

~4) 552 24.3X 1992

$ 123,948 30 915

~)54 863

$ 52,653 (3,042)

(4,402)

(2,068)

(9,011)

~3215)

~30 915 20.0X 22

~ le ~

DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES The followingtables show the elements of the net deferred tax liability and the significant temporary differences that gave rise to it:

ed for the out-of-pocket costs of energy delivered to the Power Pool and charged for energy received from the Power Pool.

Property Related Temporary Differences Amounts Oue From Customers For Future Federal Income Taxes Deferred Ket Gain-Rockport Plant Unit 2 All Other (net)

Total Ket Deferred Tax Liabilities

$ (498,124)

$ (494,966)

(109,806)

(100,432) 60,561 62,761

~)6 285) ~2) 283)

~563 654)

~553 920)

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 accor-dance 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 Coed Inc., is allocated to its subsidiaries with taxable income.

With the exception of the loss of the parent company, the method of allocation approxi-mates a separate return result for each company in the consolidated group.

December 31 1994 1993 (in thousands)

Deferred Tax Assets

$ 235,165

$ 233,380 Deferred Tax Llabllltlee

~798 810)

~787 300) liat Deferred Tax Llabllltlea ~563 654)

~553 920)

Operating revenues include

$ 140.5 million in

1994,

$204.6 million in 1993 and

$ 154.1 million in 1992 for energy and capacity supplied to the Power Pool.

Purchased power expense includes charges of $33.1 million in 1994,

$20.9 million in 1993 and

$82.6 million in 1992 for energy re-ceived 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

$ 54.1 million in 1994,

$57 million in 1993 and

$45.8 million in 1992.

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

$ 14.2 million in 1994,

$ 5.1 million in 1993 and

$6.5 million in 1992.

Reve-nues from these transactions 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 $ 82.4 million, $78.9 million and

$88 million in 1994, 1993 and 1992, respectively.

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 1988.

Returns for the years 1988 through 1990 are presently being audited by the IRS.

In the opinion of management, the final settlement of open years will not have a material effect on results of operations.

8: RELATED PARTY TRANSACTIONS:

Benefits and costs of the System's generating plants are shared by members of the Power Pool.

Under the terms of the System Interconnection Agreement, capacity charges and credits are designed to allocate the cost of the System's capacity among the Power Pool members based on their relative peak demands and generating re-serves.

Power Pool members are also compensat-The Company operates the Rockport Plant and bills AEGCo for its share of operating costs.

AEP System companies participate in a transmis-sion equalization agreement.

This agreement combines certain AEP System companies'nvest-ments in transmission facilities and shares the costs of ownership in proportion to the System companies'espective peak demands.

Pursuant to the terms of the agreement, equalization credits of

$ 50.3 million, 847A millionand $48.2 millionwere recorded in other operation expense in 1994, 1993 and 1992, respectively.

23

~

~

2 Revenues from providing barging services were recorded in nonoperating income as follows:

Year Ended Oecember 31 1994 1993 1992 (in thousands)

Affiliated Companies

$24,001

$ 21,332

$20,154 Unaffiliated Cnmpaniea 5 021 5 757 8 563 Total

~29 022

~27 089

~28 717 American Electric Power Service Corporation (AEPSC) provides certain managerial and profes-sional 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 Conf 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.

9.

FAIR VALUEOF FINANCIALINSTRUMENTS:

Nuclear Trust Funds Recorded at Market Value Effective January 1, 1994, the Company adopted SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, which requires fair value accounting for investments in equity securi-ties with readily determinable market values and investments in debt securities except those that the reporting enterprise has the positive intent and ability to hold to maturity.

Debt securities not classified as held-to-maturity and qualifying equity securities, shall be classified as trading or avail-able-for-sale.

The Company's investments held in trust funds for decommissioning nuclear facilities and for disposal of spent nuclear fuel have been classified as available-for-sale.

SFAS 116 requires that unrealized gains and losses on investments classified as available-for-sale be reported as a

separate component of shareholder's equity.

However, due to the rate-making process, adjust-ments under SFAS 116 for unrealized gains and losses to the carrying value of investments held in the trusts result in corresponding adjustments to regulatory assets and liabilities.

The cumulative effect of adopting SFAS 115 resulted in an increase in the decommissioning and spent nuclear fuel trust fund assets of

$20.4 million comprised of an unrealized holding gain of

$21A million and an unrealized holding loss of

$ 1.0 million, with no effect on net income and/or shareholder's equity. The trust investments, report-ed in other property and investments, had a fair value of 8321 million at January 1, 1994 and consisted primarily of tax-exempt municipal bonds.

In accordance with SFAS 115, prior year amounts were not restated.

At December 31, 1994, the fair value of the trust investments was $353 million. Accumulated gross unrealized holding gains and losses were

$ 5.5 million and

$ 12.2 million, respectively, at December 31, 1994.

The change in market value during 1994 was a $27.1 million net holding loss.

The trust investments'ost basis by security type at December 31, 1994 was:

(in thousands)

Treasury bonds Tax-exempt bonds Equity securities Cash and cash equivalents Total 997 332,098 1,665 25 304

~360 064 Proceeds from sales and maturities of securities were $20.1 million during 1994 which 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, 1994, the year of maturity of trust fund investments, other than equity securi-ties, was:

1995 1996-1999 2000-2004 After 2004 Total (in thousands)

$ 39,173 85,199 142,868 91 159

~358 399 Other Financial Instruments Recorded at Historical Cost The carrying amounts of cash and cash equiva-lents, 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 8117 million and $ 99 million and for long-term debt were $ 1.0 billion and

$ 1.1 bil-lion at December 31, 1994 and 1993, respectively.

24

sl ~ ~

3 The carrying amounts for preferred stock subject to mandatory redemption were $ 135 millionand $ 100 million and for long-term debt were $ 1.1 billion and

$ 1.1 billion at December 31, 1994 and

1993, respectively.

Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instru-ments of the same remaining maturities.

The carrying amount of the pre-April 1983 spent nucle-ar fuel disposal liability approximates the Company's best estimate of its fair value.

10. 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 willbe renewed or replaced by other leases.

NDIAIVAMICHIGANPOWER COMPANY AND SUBSIDIARIES Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.

Year Ended Oecember 31 1994 1993 1992 (in thousands)

$ 109,466

$ 103,884

$ 104,519 Operating Leases Amortization of Capital Leases 30,875 46,063 24,124 Interest on Capital Leases 7 643 8 073 7 473 Total Rental Costs

~143 037

~158 020

~l41 063 Future minimum lease payments consisted of the following at December 31, 1994:

Lease rentals are primarily charged to operating expenses in accordance with rate-making treat-ment.

The components of rental costs are as follows:

Properties under capital leases and related obliga-tions recorded on the Consolidated Balance Sheets are as follows:

Capital Leases (in Non-Cancelable Operating Leases thousands)

Electric UtilityPlant:

Production Distribution General:

Nuclear Fuel (net of amortization)

Other Total Electric Utility Plant Accumulated Amortization Net Electric Utility Plant Other Property Accumulated Amortization Net Other Property Net Properties under Capital Lease Capital Lease Obligations:

Noncurrent Liability Liability Oue Within One Year Total Capital Lease Obligations 8,371 14,717 8,033 14,717 89,478 53 701 45,661 40 418 166,347 27 225 116,829 27 359 139 122 09 470 15,842 2 375 13 467 152 589 11,269 1 906 9 203 98 753

$ 113,586 39 003

~152 509

$ 78,168 20 505

~90 753 Oecember 31 1994 1993 (in thousands) 1995 1996 1997 1998 1999 Later Years

$ 11,558 10,370 9,262 8,299 7,171 40 570 97,725 97,579 95,772 90,631 90,489 1 919 552 Total Future Hinimum Lease Payments 07,230(a)

~2 391 748 Less Estimated interest Element 24 119 Estimated Present Value of Future Hinimum Lease Payments Unamortized Nuclear Fuel Total 63,111 09 470

~152 509 (a) Hinimum lease rentals do not include nuclear fuel rentals.

The rentals 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.

25

0

~

iO 3

~

11. CUMULATIVEPREFERRED STOCK:

At December 31, 1994, authorized shares of cumulative preferred stock were as follows:

Par Value

$ 100 25 Shares Authorized 2,250,000 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 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:

Series Cell Price Oecenber 31, 1994 Par Value Number of Shares Redeened Year Ended Oecember 31 1992 1993 1994 Shares Outstanding Oecember 31 1994 Amount December 31 1994 1993 (in thousands) 4"1/8X 4.56K 4.12K 7.08K 7.76K

$ 106.125 102 102.728 101.85

$ 100 100 100 100 350,000 120,000 60,000 40,000 300,000

$ 12,000 6,000 4,000 30,000 52 000

$ 12,000 6,000 4,000 30,000 35 ODD

~07 ODO 3

B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Series(a)

Par Value Shares Outstanding Oecember 31 1994 Amount December 31 1994 1993 (in thousands) 5.90K (b) 6-1/4X(c) 6.30K (d) 6-7/8X(e)

$ 100 100 100 100 400,000 300,000 350,000 300,000

$ 40,000 30,000 35,000 30 000

~335 000

$ 40,000 30,000 30 000

~300 ODD (a) Not callable until after 2002.

There aro no aggregate sinking fund provisions through 2002.

(b) Shares issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund willrequire tho redemption of 20,000 shares each year and the redemption of tho remaining shares outstanding on January 1, 2009, in each case at $ 100 per share.

(c) Sharos issuod November 1993. Commencing ln 2004 end continuing through tho year 2008, a sinking fund willrequire tho redemption of 15,000 shares each year and the redemption of tho 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 willrequire the redemption of 17,500 shares each year and the redemption of tho remaining shares outstanding on July 1, 2009, in each case at $ 100 por share.

(e) Shares issued February 1993. Commencing in 2003 and continuing through tho year 2007, a sinking fund willrequire the redemption of 15,000 shares each year and tho redemption of tho remaining shares outstanding on April 1, 2008, in each case at $ 100 por share.

26

t )S

~

DIANAMICHIGANPOWER COMPANY AND S(IBSIDIARIES 12.

LONG-TERM DEBT AND LlNES OF CREDlT:

Long-term debt by major category was out-standing as follows:

Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

First Mortgage Bonds Installment Purchase Contracts Other Long-term Debt (o)

Notes Payablo to Banks Sinking Fund Debentures December 31 1994 1993 (ln thousands) 561,770 571,468 308,087 153,977 40,000 6 053 307,823 147,810 40,000 6 053 Less Portion Due Within Ono Year 1,069,887 140 000 1,073,154 Total

~929 007

~)073 154 (a) Nuclear Fuel Disposal Costs including interest accrued.

Seo Note 4.

First mortgage bonds outstanding were as fol-lows:

December 31 1994 1993 (ln thousands)

Due Rate 7

7.30 7.63 7.60 7.70 6.80 6.55 6.10 6.55 8-3/4 9.50 9.50 9.50 8.75 8.50 7.80 7.35 7.20 7.50 Unamcrti May 1 December 15 Uno 1

ovember 1

December 15 uly 1 October 1

November 1

March 1

ebruary 1

ay I ay 1

ay 1

ay 1

ecember 15 uly 1 ctobor 1

obruary 1

arch 1

ount (net) 1998-1999-2001 - J 2002-N 2002-2003-J 2003-2003-2004-2017-F 2021 - M 2021 - M 2021 - M 2022-M 2022-D 2023-J 2023- 0 2024-F 2024-M zed Disc

$ 35,000 35,000 40,000 50,000 40,000 20,000 20,000 30,000 25,000 10,000 10,000 20,000 50,000 75,000 20,000 20,000 40,000 25,000

~3230)

$ 35,000 35,000 50,000 40,000 20,000 20,000 30,000 100,000 10,000 10,000 20,000 50,000 75,000 20,000 20,000 40,000

~3532)

Total 561 770 571 468 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and re-placement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certifi-cation of unfunded property additions.

December 31 1994 1993 (in thousands)

~Rate Due City of Lawronceburg, Indiana:

7 2015-April 1 5.9 2019 - Novembor 1

City of Rockpcrt, Indiana:

9-1/4 2014-August 1

6-3/4(a) 2014 - August 1

(b) 2014-August 1 7.6 2016 - March 1 City of Sullivan, Indiana:

5.95 2009 - May 1 unamortized Discount Less Portion Due Within One Year

$ 25,000 52,000 50,000 50,000 50,000 40,000 45,000

~3913) 308,087 100 000

$ 25,000 52,000 50,000 50,000 50,000 40,000 45,000

~4) 77) 307,823 Total

~208 007

~307 023 (a) Tho adjustable interest rate will chango on August 1, 1995.

(b) Tho variable interest rate is determined weekly. The average weighted interest was 3.8% for 1994 and 3.0% for 1993.

A $40 millionunsecured promissory note payable to a bank is due November 19, 1995 at an annual interest rate of 9.07%.

The sinking fund debentures are due May 1, 1998 at an interest rate of 7-1/4%.

Prior to December 31, 1994, sufficient principal amounts of debentures had been reacquired in anticipation of all future sinking fund requirements.

Additional debentures of up to

$300,000 may be called annually.

Under the terms of certain installment purchase contracts, the Company is required to pay amounts sufficient to enable the cities to pay interest on and the principal (at stated maturities and upon mandatory redemption) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants.

On certain series the principal is payable at stated maturities or on the demand of the bond-holders at periodic interest adjustment dates.

Certain series are supported by bank letters of credit which expire in 1995.

As a result these series are classified as due within one year on the December 31, 1994 Consolidated Balance Sheet.

27

Balance Outstanding in thousands Weighted Average Interest Rate At December 31, 1994, annual long-term debt

payments, excluding premium or discount, are as follows:

Princi al Amount (in thousands) 1995 140,000 1996 1997 1998 41,053 1999 35,000 Later Years 060 933 Total

~3033 030 Short-term debt borrowings are limited by provi-sions of the 1935 Act to $200 million and further limited by charter provisions to $ 130 million. Lines of credit are shared with AEP System companies and at December 31, 1994 and 1993 were avail-able in the amounts of $558 million and $537 mil-

lion, respectively.

Commitment fees of approximately 3/16 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 commercial paper as fol-lows:

14. UNAUDITED QUARTERLY FINANCIALINFOR-IVIATION:

Ouarterly Periods Ended 1994 Harch 31 June 30 September 30 December 31 1993 Harch 31 June 30 September 30 Oecember 31 Operating Operating Net Revenues Income Income (in thousands)

$337,921

$58,815

$44,968 310,104 54,632

- 37,274 317,061 55,409 37,728 286,223 52,875 37,501 302,968 53,269 28,522 278,100 40,722 21,397 320,409 52,898 33,658 301,166 63,031 45,736 In 1994 paid-in capital was charged

$422,000 for costs associated with issuing and redeeming cumulative preferred stock.

In 1993 IS.M's parent made a cash capital contribution of $ 10 million and a charge of $ 1.2 million for the issuance of three series of cumulative preferred stock was recorded to paid-in capital. There were no other transactions affecting the common stock or paid-in capital accounts in 1994, 1993 and 1992.

December 31, 1994 Oecember 31, 1993

$ 50,600 6.3X 50,075 3.6

13. COMMON SHAREOWNER'S EQUITY:

Mortgage indentures, debentures, charter provi-sions 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, 1994,

$ 5.9 million of retained earnings were restricted.

Regulatory approval is required to pay dividends out of paid-in capital.

28

~ d

~

DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS OPERATING REVENUES (in thousands):

1994 1993 1992 1991 1990 Retail:

Residential:

Without Electric Heating With Electric Heating Total Residential Comercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Revenues from Energy Sales Provision for Refunds of Revenues Collected in Prior Years Total Het of Provision for Refunds Other 227,358 107 523 334,881 247,938 291,527 6 316 880,662 352 089 1,233,551 1,233,551 17 750 205,315 97 560 302,883 220,938 250,939 5 593 780,353 404 910 1,185,263 209,682 90 553 308,235 228,285 267,643 11 012 815,175 369 379 1,184,554 206,257 93 209 299,546 216,303 241,858 12 120 769,827 436 003 1,205,910 192,822 00 710 281,540 205,025 244,773 11 799 743,137 510 080 1,261,217 1,184,508 10 135 1,180,516 16 239 1,211,086 14 701 1,256,041 15 473

~755)

~4038) 5 176

~5176)

Total Operating Revenues 1

251 309 1 202 643 1

196 755 1 225 867 1

271 514 SOURCES ANO SALES OF ENERGY (in millions of kilowatt-hours):

Sources:

Net Generated:

Fossil Fuel Nuclear Fuel Hydroelectric Total Het Generated Purchased and Power Pool Total Sources Less:

Losses, Company Use, Etc.

Net Sources Sales:

Retail:

Residential:

Without Electric Heating

'With Electric Heating Total Residential Com)ercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Sales 13,022 9,291 95 22,408

~5757 28,165

~1398

~26 767 3,210

~1727 4,937 4,148 6,453 82 15,620

~11 147

~26 767 12,236 16,313 106 28,655

~4879 33,534

~1349

~32 185 3,178

~1706 4,884 3,977 6,025 83 14,969

~17 216

~32 185 11,597 6,418 100 18,115

~9342 27,457

~1466

~25 991 3,001

~1633 4,634 3,747 5,685 194 14,260

~II 731

~25 991 12,109 15,524 109 27,742

~5237 32,979

~1454

~31 525 3,166

~1625 4,791 3,726 5,382 233 14,132

~17 393

~31 525 14,451 11,115 127 25,693

~7983 33,676

~1633

~32 043 2,955

~1525 4,480 3,536 5,452 229 13,697

~18 346

~32 043 29

5

~ C8 OPERATING STATISTICS (Concluded)

AVERAGE COST OF FUEL CONSUNEO (in cents):

Per Nillion Btu:

Coal Nuclear Overall Per Kilowatt-hour Generated:

Coal Nuclear Overall 1994 124 42 85 1.21

.47

.90 1993 130 36 72 1.27

.40

.77 1992 136 54 103 1.34

.61 1.08 1991 141 48 84 1.39

.53

.91 990 145 58 105 1.42

.64 1.08 RESIOENTIAL SERVICE - AVERAGES:

Annual Kwh Use per Customer:

With Electric Heating Total Annual Electric Bill:

'With Electric Heating Total Price per Kwh (in cents):

With Electric Heating Total 17,907 10,572

$ 1,115.19

$717.17 6.23 6.78 17,980 10,559

$ 1,028.26

$654.76 5.72 6.20 17,513 10,107

$ 1,056.91

$ 672.31

6. 04 6.65 17,702 10,535

$ 1,016.16

$ 658.76 5.74 6.25 16,897 9,944

$983.28

$ 624.95 5.82 6.28 NUNBER OF CUSTONERS:

Year-End:

Retail:

Residential:

Without Electric Heating With Electric Heating Total Residential Camercial Industrial Hiscellaneous Total Retail Wholesale (sales for resale)

Total Customers 372,473

~97 40 469,875 53,927 5,213 1

DD6 53D,821 54

~530 875 369,385 95 795 465,180 53,081 5,157 1 783 525,201 56 525 257 366,835 94 175 461,010 52,542 5,000 1

751 520,303 53

~520 356 364,154 92 657 456,811 51,491 4,847 2 226 515.375 53 515 428 362,645 91 179 453,824 50,994 4,801 2

16D 511,779 55

~577 834 30

DIVIDENDS AND PRIG RANGES OF CUMULATIVE EFERRED STOCK By Quarters (1994 and 1993) 1994 -

uarters 1993 -

uarters CUMULATIVE PREFERRED STOCK 1st 2nd 3rd 4th 1st 2nd 3rd 4th

($ 100 Par Value) 4-1/BX Series Dividends Paid Per Share Market Price - $ Per Share (CSE)

- High

- Low

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125 4.56K Series Dividends Paid Per Share Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High

- Low

$ 1.14

$ 1.14

$ 1.14

$ 1.14 55-5/8 54-1/8 50"5/8 46-1/8 49 45-1/2 45-1/2 45-1/2

$ 1.14

$ 1.14

$ 1.14

$ 1.14 4.12K Ser ies Dividends Paid Per Share Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High

- Low

$ 1.03 58-1/2 51

$ 1.03

$ 1.03

$ 1.03 54 48 48 46-1/2 46-1/8 43-1/2 51 48 51-1/2 48 55"1/4 51 58-1/2 54-3/4

$ 1.03

$ 1.03

$1.03

$ 1.03 5.90li Series (a)

Dividends Paid Per Share Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6-1/4X Series (a)

Dividends Paid Per Share Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6.30K Series (b)

Dividends Paid Per Share Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low)

$ 1.475

$ 1.475

$ 1.475

$ 1.475

$ 1.5625

$ 1.5625

$ 1.5625

$ 1.5625

$0.9275

$ 1.575

$ 1.575

$ 1.575

$0.9342

$ 0.5382 6-7/BX Series (c)

Dividends Paid Per Share Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low)

$ 1.71875

$ 1.71875

$ 1.71875

$ 1.71875

$0.84

$ 1.71875

$ 1.71875

$ 1.71875 7.08K Series Dividends Paid Per Share Market Price - $ Per Share (MYSE) - High

- Low 97-1/2 95 94 83 87-1/2 80 80 76

$ 1.77

$ 1.77

$ 1.77

$ 1.77 92 89-1/4 96 91 99-5/8 96-3/8 100-1/8 95

$ 1.77

$ 1.77

$ 1.77

$ 1.77 31

DIVIDENDS AND PRIG RANGES OF CUMULATIVEP EFERRED STOCK

~

By Quarters (1994 and 1993) (Concluded) 1994 -

uarters 1993 -

uar ters CUMULATIVE PREFERREO STOCK 1st 2nd 3rd 4th 1st 2nd 3rd 4th 7.76K Series (Redeemed)

Dividends Paid Per Share Market Price - $ Per Share (NYSE) - High

- Low

($ 100 Par Value) 8.68K Series (Redeemed)

Dividends Paid Per Share Market Price - $ Per Share (MYSE) - High

- Low

($ 25 Par Value)

$2. 15 Series (Redeemed)

Oividends Paid Per Share Market Price - $ Per Share (NYSE) " High

- Low

$2.25 Series (Redeemed)

Oividends Paid Per Share Market Price - $ Per Share (MYSE) - High

- Low

$0.9054 101 100

$ 1.94

$ 1.94

$ 1.94

$ 1.94 102-1/4 102 95-3/4 98 104 102-3/4 100 98-1/2

$2.17

$2.17

$2.17

$ 1.8807 103 103-1/2 104 103 100 101 101 101-1/4

$0.375 26-3/4 25-1/2

$0.5375

$0.5375

$0.5375

$ 0.2628 27-1/2 27-1/4 27"3/8 26-1/2 26 26-1/4 25-3/4 25-5/8 CSE

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(a) Issued November 1993 (b) Issued February 1994 (c) Issued February 1993 32

u DIANAMICHIGANPOWER COMPANY SECURITY OWNER INQUIRIES Security owners should direct their inquiries to the Security Owner Relations Division using the toll free number: 1-800-AEP-COMP (1-800-237-2667) or by writing to:

Bette Jo Rozsa Security Owner Relations Division American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUALREPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1995 at no cost to shareowners.

Please address such requests to:

Geoffrey C. Dean American Electric Power Service Corporation 27th Floor 1 Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVEPREFERRED STOCK First Chicago Trust Company of New York P.O. Box 2534 Suite 4692 Jersey City, NJ 07303-2534 33

Indiana Michigan Power Service Area and the American Electric Power System LAKE MICHIGAN MICHIGAN IAKE ERIE OHIO INDIANA WEST VIRGINIA KENTUCKY VIRG IN I A Indiana Michigan Power Co. area

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ATTACHMENT 2 TO AEP:NRC'0909K INDIANAMICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1995

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Indiana Michigan Power Co.

1995 Forecasted Sources and Uses of Funds Based on Forecasted Case 9501

$ Millions Projected 1995 Net Income AfterTaxes Less Divklends Paid 136.4 122.5 Retained Earnings Adjustments:

Depreciation And Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Other 13.9 163.0 2.9 (26.4)

(3.1) 7.7 Total Adjustments 144.1 Internal Cash Flow 158.0 Average Quarterly Cash Flow 39.5 Average Cash Balances and Short-Term Investments 8.9 Total

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