ML17331B339

Indiana Michigan Power Company 1993 Annual Rept. W/Projected Cash Flow for 1994 &

ML17331B339
Person / Time
Site:	Cook
Issue date:	12/31/1993
From:	Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909J, AEP:NRC:909J, NUDOCS 9404130143
Download: ML17331B339 (43)

Text

.ACCELERATED D. TRIBUTION DEMONSTPWTION SYSTEM

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"i REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9404130143 DOC.DATE: /~+53.

NOTARIZED: NO DOCKET 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 FITZPATRICK,E.

Indiana Michigan Power Co.

(formerly Indiana

& Michigan Ele RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"Indiana Michigan Power Company 1993 Annual Rept."

W~B4040 ltr DISTRIBUTION CODE M004D COPIES RECEIVED:LTR ENCL SIZE:

TITLE: 50.71(b)

Annual Financial Report NOTES:

D RECIPIENT ID CODE/NAME PD3-1 LA HICKMAN,J INTERNAL: AEOD/DOA EXTERNAL: NRC PDR COPIES LTTR ENCL 1

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1 RECIPIENT ID CODE/NAME PD3-1 PD 01 COPIES LTTR ENCL 1

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D NOTE TO ALL"RIDS" RECIPIENTS PLEASE HELP US TO REDUCE WASTE! CONTACT THE DOCUMENT CONTROL DESK, ROOM Pl-37 (EXT. 20079) TO ELIMINATEYOUR NAMEFROM DISTRIBUTION LIFfS FOR DOCUMENTS YOU DON'7 NEED!

TOTAL NUMBER OF COPIES REQUIRED:

LTTR 6

ENCL 6

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Indiana Michigan~

Power CompaIy ~

P.O.'Box 16631 Columbus, OH 43216 AEP: NRC: 0909 J 10 CFR 50.71(b) 6 140.21(e)

Donald C.

Cook Nuclear Plant Units 1 and 2

Docket Nos.

50-315 and 50-316 License Nos.

DPR-58 and DPR-74 FINANCIAL INFORMATION FOR INDIANAMICHIGAN POWER COMPANY U.

S. Nuclear Regulatory Commission Document Control Desk Washington, D.C.

20555 Attn:

W. T. Russell April 6, 1994

Dear Mr. Russell:

Enclosure 1 contains the Indiana Michigan Power Company's '(I&M) annual report for 1993.

Enclosure 2 contains a

copy of I&M's projected cash flow for 1994.

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

Sincerely, E.

E. Fitzpatrick

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Vice President dr Enclosures cc:

A. A. Blind G. Charnoff J.

B. Martin - Region III NRC Resident Inspector NFEM Section Chief J.

R. Padgett 9404130143 931231 PDR ADOCK 05000315' I

('

PDR.',,

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ENCLOSURE 1 TO AEP:NRC:0909J INDIANAMICHIGAN POWER COMPANY' 1993 ANNUAL REPORT

0 1993 Annual Report

CONTENTS 0

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Management's Discussion and Analysis of Results of Operations and Financial Condition..........

4-9 Independent Auditors'eport....

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o 10 Consolidated Statements of Income

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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

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tINDIANAMICHIGANPOWER COMPANY AIVDSUBSIDIARIES 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 serving approximately 525,000 retail customers in northern and eastern Indiana and a portion of southwestern Michigan and supplying wholesale electric power to other electric utilities, municipalities and electric cooperatives.

Approximately 83o%%d of the Company's retail sales are in Indiana and 17o%%d in Michigan. The principal industries served are transportation equipment, primary metals, 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 has its principal executive offices in Fort Wayne, Indiana.

Indiana Michigan Power Company was organized under the laws of Indiana on February 21, 1925, and is also authorized to transact business in Michigan and West Virginia.

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 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 interconnected with its affiliate, AEP Generating

Company, and the following unaffiliated entities:

Central Illinois Public Service Company, The Cincinnati Gas

&, 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.

DIRECTORS Mark A. Bailey Peter J. DeMaria Richard E. Disbrow (a)

William N. D'Onofrio A. Joseph Dowd (b)

E. Linn Draper, Jr.

Allen R. Glassburn (c)

OFFICERS William J. Lhota Gerald P. Maloney Richard C. Menge Ronald E. Prater (d)

David B. Synowiec (d)

Dale M. Trenary (c)

William E. Walters Richard E. Disbrow (a)

Chairman of the Board and Chief Executive Officer Gerald P. Maloney Vice President E. Linn Draper, Jr. (b)

Chairman of the Board and Chief Executive Officer James J. Markowsky (f)

Vice President Richard C. Menge President and Chief Operating Officer John F. DiLorenzo, Jr.

Secretary Mark A. Bailey Vice President 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 Vice President John B. Shinnock Assistant Secretary Eugene E. Fitzpatrick Vice President Leonard V. Assante Assistant Treasurer Richard F. Hering (e)

Vice President Bruce M. Barber Assistant Treasurer William J. Lhota Vice President Gerald R. Knorr Assistant Treasurer As ofJanuary 1, 1994 the current directors and off(cars ofIndiana Michigan Power Company were employees ofAmerican E/ectr(c Rower Service Corporation with eight exceptions: Messrs. Bafile, Bailey, D'Onofno, Mange, Moos, Proter, Synowiec and We(ters, who were employees of Indiana Mt'eh(Pan Power Company.

(el Resigned Apn7 28, 1993 (bl E(ected Apn7 28, 1993 (cl Ree'gned Apn7 27. 1993 (dl Elected Apnt 27, 1993 (el Rex'gned Juty 1, 1993

(/1 Elected Juty 1, 1993

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data INCOME STATEMENTS DATA:

rEn D

m

~1 (in thousands)

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

$ 1,202,643

~992 72 209,920

~24 i 209,686

~80 37 129,313

~14 22 4

115 088

$ 1,196,755

~1Q)~12 195,520

~ts 11 209,635 tL5 687 123,948

~141 7

~108 531 S1,225,867 227,289

~72 1 223,568

~636 136,932

~tet 7

~l21 515 01,271,514

~1(~7~2 201,491

~77 209,048 9~7 118,391

~17

~102 804 01,135,587

~~~21 g4 213,983

~~27 246,720

~1~74 139,237 1~4 121 18 BALANCE SHEETS DATA:

199 1992 m

r 1

~11 (in thousands)

Electric UtilityPlant Accumulated Depreciation and Amortization Net Electric Utility Plant

$4,290,957

$4,266,480 04,135,820 S4,066,227 03,969,602 1714 l72

~1'1~14

[ ~12~14

~l421 2

~F8,~7

~2576 '128 42 635 042

~2614 471

~2644 942

~2660 53 Regulatory Assets (a)

S 492 822

~4268 81 204 060 240 754 280 76 Total Assets 43 765 458

~3645 798

~3481 78

~3501 92

~41 25 53 Common Stock and Paid-in Capital Retained Earnings Total Common Shareowner's Equity 791,517 S

782,741 0

782,741 0

782,741 0

782,741 177tftt 17~1

~1~24 1'i~4[ ~12 21 4

969 155 4

954 050 4

951 984 4

933 149 4

944 954 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption S

87,000 Subject to Mandatory Redemption (b) 1~9'otal Cumulative Preferred Stock

~187 000 197,000

~197 000 197,000

~197 000 197,000

~197 00 197,000 M1LQK

~215 03 Long-term Debt (b) 1 073 154 1 211 62 1 130 709 1 133 83 1 532 73 Obligations Under Capital Leases lbl 4

98 753 4

126 689 4

102 985 133 447 123 361 Total Capitalization and Liabilities 43 765 458 43 645 798 43 481 878 3 501 925

~4125 534 lal Effective January 1, 1993 o naw accounting standard Statement of Rnanciel Accounting Standards No. 109, Accounting for Income Taxes, was adopted resulting in on Increase In regulatory assets.

(See IVota 1 of Notes to Consolidated Rnanclal Stotemontsl.

fbI Including portion due within ona year.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIALCONDITION Net Income Increases Net income increased 4.3% in 1993 and de-creased 9.6% in 1992. The scheduled refueling of the two nuclear generating units and an unsched-uled outage at one of the units in 1992 required the purchase of more expensive replacement power from the AEP System Power Pool (Power Pool) and reduced wholesale sales to the Power Pool reduc-ing net income in 1992.

The return to service of the nuclear units along with the retirement and the refinancing of debt at lower interest rates was responsible for the increase in net income in 1993.

Outlook The electric utility industry is expected to undergo significant changes for the remainder of the decade because of increasing competition in the generation and sale of electricity and increasing energy flows resulting from open transmission access.

Although management believes that the Company is well positioned, as a low cost produc-er, to compete, efforts will continue to further reduce costs and increase effectiveness.

The Company faces additional challenges from compliance with the Clean AirAct Amendments of 1990, other environmental concerns and costs, the cost of operating, maintaining and eventually decommissioning the two nuclear generating units and the disposal of their spent nuclear fuel that could affect financial performance and possibly the ability to meet financial obligations and commit-ments.

While management believes the Company is equipped to meet these challenges, future finan-cial performance is heavily dependent on the ability to obtain favorable rate-making treatment to recov-er costs of service on a timely basis.

Future results of operations will be affected by several factors, including the continued economic health of our service territory, the weather, compe-tition for wholesale sales, new environmental laws and regulations and the rate-making policies of the Company's regulators.

Many of these factors are not generally within management's direct control yet every effort will be made to work with regula-tors, government officials, and current and pro-spective customers to positively influence these critical factors and to take advantage of the oppor-tunities increased competition will bring.

Operating Revenues and Energy Sales Operating revenues increased

$6 million in 1993 following a decline of $29 million in 1992.

The 1993 increase and the 1992 decrease were attrib-utable to the Donald C. Cook Nuclear Plant (Cook Plant) generating units being out of service for scheduled refueling and maintenance and an un-scheduled outage in 1992 which reduced the amount of energy the Company had available for sale to the Power Pool.

Retail:

Price variance Volume variance

$ (75.1) 42.3

~3

~34.6) (4.3) 45 3

5.9 Wholesale

Price variance Volume variance (137.2) 172.7,

35. 5 Othev Opevetln9 Revenues 5.2 Total

~5. 9 75.2

~(41

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9.6

~66.7)(15.3)

~7.7) 0.5

~29.() (2.4)

The unfavorable retail and wholesale price variances in 1993 reflect the operation of fuel and power supply cost recovery mechanisms due to the availability of the Cook Plant and lower average cost generation.

Under the retail jurisdictional fuel

clauses, revenues were accrued in 1992 for future recovery of higher cost replacement power during the nuclear outages.

The increase in 1993 retail sales volume re-flects continuing improvement in industrial sales, a

return to normal weather and moderate growth in residential and commercial customer classes.

The increase in wholesale sales volume in 1993 result-ed from the increased availability of energy for delivery to the Power Pool due to availability of the Cook Plant as well as increased sales by the Power Pool to unaffiliated utilities which the Company shares as a member of the Pool.

The changes in revenues can be analyzed as follows:

Increase (Decrease)

From Previous Year

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dollars in millions 1993 1992

~unt ~

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t INDIANAMICHIGANPOWER COMPANV AND SUPSIDIARIES Operating Expenses Decline Changes in the components of operating ex-penses were as follows:

Increase (Oecrease)

From Previous Year dollars in millions 1993 1992

~unt ~

~unt

$ (57.5) (22.9) 57.8 47.1 5.0 2.0 18.5 15.6

$ 26.4 13.6 (72.0)(40.0) 12.6 5.0 4.9 3.5 Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization 5.4 4.1 Amortization of Rockport Plant Unit I Phase-in Plan Oeferrals (0.7) (4.0)

(0.7)

(3.9)

Taxes Other Than Federal Income Taxes 5.7 9.2 (0.6)

(0.9)

Federal Income Taxes

~9.

36. I

~20.9)

(45.1)

Total

~8.5)

(0.9) ~2.7 0.3 1.1 0.8 Fuel expense increased in 1993 due to the significant increase in nuclear generation and a 6%

increase in fossil generation, partially offset by a decrease in the average cost of fuel. The reduction in fuel expense in 1992 resulted largely from reduced generation due to outages at the two nuclear units as well as lower average fossil fuel costs.

The substantial retail and wholesale price vari-ance in 1992 resulted from recovery of higher fossil fuel generation costs and power pool pur-chases which were incurred during the Cook Plant outages.

The reduction in 1992 wholesale sales volume reflects a decrease in sales to the Power Pool because of the Cook Plant outages and re-duced wholesale sales by the Power Pool, Efforts to improve short-term wholesale sales are affected by the highly competitive nature of the short-term energy market and other factors such as unaffiliat-ed generating plant availability, the weather and the

economy, that are not generally within management's control ~ Future results of operations will be affected by the ability to make cost-effec-tive wholesale sales or, if such sales are reduced, the ability to timely raise retail rates.

The decline in purchased power expense in 1993 reflects a reduced level of energy receipts from the Power Pool because of the increased availability of the nuclear units and reduced power purchases from AEP Generating Company as a result of Rockport Plant maintenance outages.

The increase in purchased power expense in 1992 was the result of an increased level of energy receipts from the Power Pool during the nuclear outages.

Certain other operation and maintenance proce-dures can be performed only when a nuclear unit is out of service.

Therefore, during the 1992 nuclear refueling outages, significant other operation and maintenance expenses were incurred.

However, the impact on 1992 earnings from refueling outag-es was mitigated through the implementation of levelized accounting in 1992. Levelized accounting spreads the incremental cost of refueling outages so that the cost of an average number of refuelings are reflected in each year's expenses.

The Compa-ny received regulatory approval to defer incremen-tal nuclear refueling outage costs and to amortize them from the start of an outage until the begin-ning of the next outage.

As a result, 1993 operat-ing expenses include the amortization of $35.2 million of incremental nuclear refueling outage expenses that were deferred in 1992.

Taxes other than federal income taxes in-creased in 1993 primarily due to a substantial increase in Indiana supplemental net income tax because the nuclear refueling outage costs incurred in 1992 were tax deductible in that year.

There were no refueling outages in 1993. Federal income taxes attributable to operations increased in 1993 due to an increase in pre-tax operating income and a reduction in interest charges.

The decline in federal income taxes attributable to operations in 1992 reflects a

decrease in pre-tax operating

income,

Nonoperating Income and Financing Costs Decline Construction Spending Nonoperating income declined in 1993 due to the implementation of Statement of Financial Accounting Standards No. 109, Accounting for Income Texes, the recordation in 1992 of interest income on federal income tax refunds in connection with the settlement of audits of prior years'ax returns and the reversal of a provision in 1992 as a result of the successful settlement of a coal royalty dispute with the state of Utah.

Interest expense declined in 1993 due to the retirement of $ 142 million of long-term debt and the refinancing of $ 150 million of long-term debt and

$97 million of installment purchase contracts (IPC) at lower interest rates.

The decline in 1992 was largely attributable to the refinancing of $25 million of IPCs and a lower average interest rate on a variable rate IPC.

Accrued UtilityRevenues and Taxes Accrued At December 31, 1992 under retail fuel and power supply cost recovery mechanisms,

$38 million of fuel revenues were accrued related to fuel and replacement power costs incurred during the nuclear unit outages.

Both retail jurisdictions approved recovery.

Recovery was completed in the Indiana jurisdiction and substantially completed in the Michigan jurisdiction in 1993 reducing the accrued utility revenues balance at December 31, 1993.

The remaining balance in the Michigan jurisdiction will be recovered in 1994.

Taxes accrued increased in 1993 reflecting the effects of federal income tax return audit settle-ments recorded in 1992.

A significant refund resulting from the audit caused a reduction in the 1992 balance.

Regulatory Assets and Deferred Tax Liabilities Increase The Company prospectively adopted a

new accounting standard for income taxes on January 1, 1993.

The new standard required, among other things, that regulated entities record deferred tax liabilities on temporary differences previously flowed-through for rate-making and book account-ing. Where rate-making provides for flow-through treatment, corresponding regulatory assets were recorded resulting in an increase in total assets and liabilities.

Gross plant and property additions were $ 125 millionin 1993 and $ 176 million in 1992. Manage-ment estimates construction expenditures for the next three years to be $410 million. The funds for construction of new facilities and improvement of existing facilities come from a combination of internally generated funds, short-term and long-term borrowings and investments in common equity by the Company's parent, American Electric Power

Company, Inc.

(AEP Co.,

Inc.).

Approximately 92% of the construction expendi-tures for the next three years will be financed internally with the remainder financed externally.

Capital Resources The Company generally issues short-term debt to provide for interim financing of capital expendi-tures that exceed internally generated funds.

At December 31, 1993, unused short-term lines of credit of

$537 million shared with other AEP System companies were available, Short-term borrowings increased by $5.9 million in 1993.

A charter provision limits short-term borrowings to

$ 127 million.

Periodic reductions of outstanding short-term debt are made through issuance of long-term debt and preferred stock and through equity capital contributions by the parent company.

The Company received or has requested regula-tory approval to issue up to $ 185 million of long-term debt and preferred stock.

Management expects to use the proceeds to retire short-term debt, refinance higher cost and maturing long-term debt, refund cumulative preferred stock and fund construction expenditures.

Unless the Company meets certain earnings or coverage tests, additional long-term debt or pre-ferred stock cannot be issued.

In order to issue long-term debt without refunding an equal amount of existing debt, pre-tax earnings must be equal to at least twice annual interest charges on long-term debt after giving effect to the new debt.

To issue additional preferred stock, after-tax gross income must be at least equal to one and one-half times annual interest and preferred stock dividend re-quirements after giving effect to the new preferred stock.

The Company presently exceeds these minimum coverage requirements. AtDecember 31, 1993, long-term debt and preferred stock coverage ratios were 4.59 and 2.48, respectively.

Recently a major credit rating agency reevaluat-ed the credit worthiness of companies in the electric utilityindustry based on perceived risk from deregulation, increased competition, reduced load growth, escalating nuclear plant costs and environ-mental concerns.

The agency lowered its ratings outlook for approximately one-third of the com-panies but not for Indiana Michigan Power which was regarded by the agency as being relatively well positioned to meet future competitive challenges.

Competition INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Although management may have opportunities to improve shareholder value through increased competition as a result of open transmission access and other provisions of the Energy Policy Act of 1992, there is risk and uncertainty, especially for retail ratepayers and shareholders, regarding reli-ability of future transmission service and fair compensation for use of the Company's extensive high voltage transmission facilities. Management's goal is to ensure that, to the extent the Company's facilities are used by others, there is fair and appropriate compensation.

Since 1990, the short-term wholesale energy market has been extremely competitive.

With the passage of the Energy Policy Act of 1992, which provides for greater ease of transmission access and reduces certain regulatory restrictions for independent power producers (IPPs), competition is expected to increase in the long-term wholesale market and in the construction of new generating capacity.

For example, IPPs are no longer required to find an industrial host to utilize the steam by-product from the generation of electricity to build a generating unit and avoid regulation under the Public UtilityHolding Company Act of 1935 (1935 Act).

The Energy Policy Act also exempts IPPs from requirements under the 1935 Act which, among other things, permit IPPs to use greater amounts of lower cost debt which may reduce overall cost of capital.

Thus IPPs may have a

competitive advantage.

Although the Energy Policy Act specifically prohibits the Federal Energy Regula-tory Commission from ordering retail transmission access, the states can do so and many believe that the next logical step will be the extension of com-petition for existing industrial customers which will present both opportunities and challenges for the Company.

Although management believes that the Compa-ny is well positioned to compete in this evolving competitive market because of its technical skills and expertise and its position as a low cost produc-er, we intend to continue to examine ways to im-prove the Company's competitive position. Efforts to improve operations and reduce costs willcontin-ue,in order to maintain and enhance our position as a low cost producer.

Environmental Concerns and Cost Pressures Clean AlrAct The Clean Air Act Amendments of 1990 (CAAA) require, among other things, substantial reductions in sulfur dioxide and nitrogen oxides emitted from electric generating plants, Two of the Company's generating units, Tan-ners Creek Unit 4 and the Breed Plant, are affected by the first phase of the CAAA. Tanners Creek Unit 4 will comply by fuel switching at minimal capital cost. Management decided early in 1994 to close the 325 megawatt (mw) Breed Plant as of March 31, 1994, due to its design and age (com-mercial operation began in 1960) as well as the additional cost of complying with the CAAA.

The closing of the Breed Plant is not expected to adversely affect results of operations or financial condition except as it impacts ongoing Power Pool credits and charges.

The ongoing earnings effe'ct of closing the Breed Plant will be that the Company will receive less capacity credits for being a net supplier to the Power

Pool, partially offset by a

reduction in operation, maintenance and depreciation expenses.

As of December 31, 1993 the unfavorable effect on earnings is expected to be $ 10 millionannually.

The Company will seek recovery of this additional cost in future rate cases, Phase II of the CAAA, effective in the year

2000, will require further actions to comply.

Additional costs willbe incurred and recovery from customers will be sought for all CAAAcosts.

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

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

The AEP System supports the plan and willwork with the U.S. Department of Energy (DOE) and other electric utilitycompanies to formulate a cost effective framework for limiting future greenhouse gas emissions.

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

To reduce emissions, we support energy conservation programs, development ofmore efficient generation and end-use technologies, and forest management activities because they are cost effective and bring long-term benefits to our service area.

Should significant new measures to control the burning of coal be enacted, they could affect the Company's competitiveness and, ifnot recovered from custom-

ers, adversely impact results of operations and financial condition.

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 EMF research to help determine the extent, if any, to which EMF may adversely impact public health.

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

As long as there is uncertainty about EMF, we will have difficulty finding acceptable sites for our transmission facil-ities, which could hamper economic growth within our service area.

If the present energy delivery system must be changed because of EMF con-cerns, or ifthe courts conclude that EMF exposure harms individuals and that utilities are liable for

damages, then results of operations and financial condition could be adversely affected, unless the costs can be recovered from customers.

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

In addition, generating plants and transmission and distribution facilities have used

asbestos, polychlorinated biphenyls (PCBs) and other hazard-ous and non-hazardous materials.

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

Significant additional costs could be incurred to comply with new laws and regulations if enacted and to clean up disposal sites under existing legislation.

The Superfund created by the Comprehensive Environmental Response Compensation and Liability Act addresses cleanup of hazardous substance disposal sites and authorizes the United States Environmental Protection Agency (Federal EPA) to administer the cleanup programs.

The Company has been named by the Federal EPA as a "potential-ly responsible party" (PRP) for seven sites and has received information requests for three other sites.

For two of the PRP sites, liability has been settled with little impact on results of operations.

I%M also has been named a PRP at one Illinois site and has received an information request for one Indiana site under analogous state cleanup laws. Although the potential liabilityassociated with each site must be evaluated individually, several general state-ments can be made regarding such potential liabili-

INDIANAMICHlGANPOWER COMPANY AND SUBSIDIARIES Whether the Company disposed of hazardous substances at a particular site is often unsubstan-tiated; the quantity of material disposed of at a site was generally small; and the nature of the material generally disposed of was non-hazardous, Typical-ly, the Company is one of many parties named PRPs for a site and, although liability is joint and

several, at least some of the other parties are financially sound enterprises.

Therefore, present estimates do not anticipate material cleanup costs for identified disposal sites.

However, if for un-known reasons, significant costs are incurred for cleanup, results of operations and possibly financial condition would be adversely affected unless the costs can by recovered from insurance proceeds and/or customers.

Nuclear Operating Cost Operation and maintenance costs of the Comp-any's two-unit 2,110 mw Donald C. Cook Nuclear Plant are directly impacted by increasing Nuclear Regulatory Commission requirements and increas-ing maintenance requirements related to the aging of the units (Unit 1 began commercial operation in 1975 and Unit 2 in 1978).

While nuclear fuel cost has declined, the estimated cost to decommission the plant has increased to a range of $588 million to $ 1.1 billion.

The increase in the range from previous estimates is attributable to uncertainty regarding future delays in the DOE's mandatory Spent Nuclear Fuel (SNF) disposal program. Delays in finding a permanent repository for SNF have in-creased costs reflecting a need to store SNF at the plant site for an extended time after the plant ceases operations.

Management intends to contin-ue to seek recovery of increasing decommissioning costs over the remaining plant life. We continue to examine our operations for better ways to operate and maintain our two nuclear units to control the growth in operation, maintenance and decommis-sioning costs.

Management recently restructured its nuclear operations and staff to address these concerns.

Efforts are continuing to shorten refuel-ing and maintenance outages, to reduce their cost and to minimize the cost of replacement energy during the outage periods.

Should the nuclear units be retired early for any reason or costs of maintain-ing, operating and decommissioning the plant and disposing of its spent nuclear fuel not be recovered through rates, results of operations and financial condition would be adversely affected.

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

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

New Accounting Standards Two new accounting standards were issued in 1993 that were adopted in 1994. The implementa-tion of these new standards willnot have a signifi-cant effect on results of operations or financial condition.

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

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

timely basis.

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

INDEPENDENT AUDITORS'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, 1993 and 1992, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Company's management.

Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards.

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.

An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles.

As discussed in Notes 1 and 6 in Notes to Consolidated Financial Statements, effective January 1, 1993, the Company changed its method of accounting for income taxes to conform with Statement of Financial Accounting Standards No.

109 "Accounting for Income Taxes,"

and its method of accounting for postretirement benefits other than pensions to conform with Statement of Financial Accounting Standards No.

106 "Employers'ccounting for Postretirement Benefits Other Than Pensions."

win~

DELOITTE 5 TOUCHE Columbus, Ohio February 22, 1994

Consolidated Statements of Income INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Y rE D

m r

~12 (in thousands)

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 220,206 108,274 264,543 142,637 138,794 193,830 180,365 251,897 137,787 133,365 251,325 122,573 246,935 119,242 132,285 16,961 62,783

~4474 16,303 62,189 2!~4 15,644 67,918

~47 7

~2~72

~1~2

~~7

~12 ~24

~11 L77

~1~22'jJ+7 OPERATING INCOME NONOPERATING INCOME (LOSS)

INCOME BEFORE INTEREST CHARGES INTEREST CHARGES NET INCOME PREFERRED STOCK DIVIDENDREQUIREMENTS EARNINGS APPLICABLETO COMMON STOCK 209,920 195,520 227,289 209,686 209,635 223,568

~MiGZ

~MQ5.

129,313 123,948 136,932

~14 22

~141 1'~

~115 088

~108 531

~121 51

~21

~411

~21 See Notes to Consolidated Financiel Statements.

11

Consolidated Balance Sheets ASSETS m

r 1

~1

~12 (in thousands)

ELECTRIC UTILITYPLANT:

Production Transmission Distribution General (including nuclear fuel)

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

$2,559,905 829,507 576,309 182,414

~11 4

02,602,527 839,198 608,752 152,470 4,290,957

~7~42 4,266,480

~~4

~27~12

~2;~~42 OTHER PROPERTY AND INVESTMENTS

~4~24 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 3,752 7,459 67,246 24,507 30,087 (504) 34,476 57,800 34,642

~12 4

62,325 41,139 31,536 (562) 53,210 54,004 78,555

~11 1

~2~44

~QUUL22.

REGULATORY ASSETS:

Amounts Due From Customers For Future Federal Income Taxes Other TOTAL REGULATORY ASSETS 286,948

~2~74

~42 2

~2LRK TOTAL See lvotes to Consolideted Rnenoiel Stetements.

3 765 458

~3845 798 12

IND NA MICHIGANPOWER COMPANY AND SUBSIDIARIES CAPITALIZATIONAND LIABILITIES m

r

~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 Shareowner's Equity Cumulative Preferred Stock:

Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION 56,584 726,157 171~

S 56,584 734,933 17~7 954,050

'969,155 197,000

~11

~72 87,000 100,000

~17~14

~222~$

~21!~71 OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES:

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

General 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 3)

~21 7

~27~

50,075 40,437 17,481 54,473 18,894 20,585 7,'~7 42,902 44,200 37,214 12,471 15,829 22,759 32,745

~1LQ32

~1'MM4 211 44

~2'~4 1

242 17 7

~21 1 2

~2I~11 TOTAL

$3 765 458 3 645 79

Consolidated Statements of Cash Flows 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 INVESTING ACTIVITIES:

Construction Expenditures Proceeds from Sales of Property and Other Net Cash Flows Used For Investing Activities 93 S 129,313 148,270 15,644 33,827 (49,905)

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

~17~4

~7~72 (108,867)

~i2Li

~1'~42) rEn D

m 1 992 (in thousands) 0 123,948 141,453 16,303 (47,200) 29,897 (9,673)

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

(15,088) 4,514

~1I~44

~122M2 (125,908)

J1%$2$

S 136,932 141,813 16,961 (21,877)

(9,188)

(4,389)

(14,520) 3,816 (15,222) 9,937

~444

~24 ~7 (122,597)

~24

~LAD 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 See Notes to Consolidated RnanoIol Statements.

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

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

~1~7~

271,722 (203,185)

(6,750)

(106,465)

~141 7 78,634 (92,623) 12,055 (102,680)

~141 7 (3,707)

~74 3 752 (4,876) 12~

7 459 9,327

~hQQR

~27 )~7

~I~)

~2~391 14

. ~

Consolidated Statements of Retained Earnings t INDIANAMICHIGANPOWER COMPANY AND SU8SIDIARIES Y

rEn D

m 1

~12 (in thousands)

Retained Earnings January 1

Net Income 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 6-7/8% Series 7.08%

Series 7.76%

Series 8,68%

Series

$2.15 Series

$2.25 Series Total Cash Dividends Declared Other Total Deductions Retained Earnings December 31 0171,309

~12 1~1

~01~22 108,696 495 273 165 374 161 1,799 2,124 2,716 2,517 3,001 122,921 122 4

~177 638

$ 169,243

~12 l~4

~2I~11 106,465 495 273 165 2,124 2,716 2,604 3,440

~l~

121,882

~121 2

171 30

$ 150,408

~i~2

~27~4 102,680 495 273 165 2,124 2,716 2,604 3,440

~)~

118,097 11~!L7

~I69 24 See Notes to Consolidoted Rnancial Statements.

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

1. SIGNIFICANTACCOUNTING POLICIES:

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

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

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

the recognition of revenues and expenses in differ-ent time periods than enterprises that are not rate regulated.

In accordance with Statement of Finan-cial Accounting Standards (SFAS) No. 71, Ac-counting forthe Effects ofCertain Types ofRegula-tion (SFAS 71), regulatory assets and liabilities are recorded to defer expenses or revenues reflecting such rate-making differences.

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, IRM 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.

Principles of Consolidation The consolidated financial statements include ISM and its wholly-owned subsidiaries.

Significant intercompany items were eliminated in consolida-tion.

Basis ofAccounting As a rate-regulated entity, I@M's financial state-ments reflect the actions of regulators that result in 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 income item that is recov-ered over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance con-struction projects.

The average rates used to accrue AFUDC were 8.75% in 1993 and 9.25% in 1992 and 1991 and the amounts of AFUDC ac-crued were

$ 1.7 million, $3.8 million and S2.1 million in 1993, 1992 and 1991, respectively.

Depreciation and Amortization Depreciation is provided on a straight-line basis over the estimated useful lives of utility plant and is calculated largely through the use of composite rates by functional class (i.e., production, transmis-sion, distribution, etc.).

Amounts to be used for demolition of non-nuclear plant are presently recovered through depreciation charges included in rates.

The accounting and rate-making treatment afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3.

16

. ~

t INDIANAMICHIGANPOVYER COMPANY AND SUBSIDIARIES Rockport Plant Income Texes Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units.

ILM and AEP Generating Company (AEGCo), an affiliate, each owns 50% of one unit (Rockport

1) and each leases a 50%

interest in the other unit (Rockport 2) from unaffili-ated lessors under an operating lease.

The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022.

Rate phase-in plans provide for the recovery and straight-line amortization through 1997 of prior-year deferrals of Rockport 1

costs.

Deferred amounts under the phase-in plans were $59 million and $75 million at December 31, 1993 and 1992, respectively.

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

Operetin g Revenues Revenues include an accrual for electricity con-sumed but unbilled at month-end as well as billed

revenues, Fuel Costs 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.

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

Levelization of Nuclear Refueling Outage Costs Increme'ntal operation and maintenance costs associated with refueling outages at the Donald C.

Cook Nuclear Plant (Cook Plant) are deferred with the approval of regulators for amortization over the period (generally eighteen months) beginning with the commencement of an outage until the begin-ning of the next outage.

Deferred amounts were

$ 13.4 million and

$47.2 million at December 31, 1993, and 1992, respectively.

Effective January 1, 1993, the Company adopted the liabilitymethod of accounting for income taxes as prescribed by SFAS 109, Accounting forIncome Texes. Under this standard deferred federal income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities which will result in a future tax conse-quence.

In prior years deferred federal income taxes were provided fortiming differences between book and taxable income except where flow-through accounting for certain differences was reflected in rates.

Flow-through accounting is a method whereby federal income tax expense for a particular item is the same for accounting and rate-making as in the federal income tax return.

As a result of the adoption of SFAS 109 significant additional deferred tax liabilities were recorded for items afforded flow-through treatment in rates.

In accordance with SFAS 71 significant corresponding regulatory assets were also recorded to reflect the future recovery of additional taxes due when the temporary differences reverse.

As a result of this change in accounting effective January 1, 1993, deferred federal income tax liabilities increased by

$259.6 million and regulatory assets by $254.3 million, and net income was reduced by

$5.3 million.

Investment tax credits utilized in prior years'ederal income tax returns were deferred and are being amortized over the life of the related plant investment in accordance with rate-making treat-ment.

Debt and Preferred Stock Gains and losses on reacquired debt are deferred and amortized over the term of the reacquired debt.

Ifthe debt is refinanced the reacquisition costs are deferred and amortized over the term of the re-placement debt.

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

17

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

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

Other Property and /nvestments Other property and investments are generally stated at cost.

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

operation from the Company in 1986 and affiliated coal transportation charges.

In December 1993 the wholesale customer appealed the FERC order to the U.S. Court of Appeals.

3. COMMITMENTSAND CONTINGENCIES:

Construction and Other Commitments Substantial construction commitments have been made although no new generating capacity is expected to be constructed until the next century.

The aggregate construction program expenditures for 1994-1996 are estimated to be 0410 million and include the capital cost of compliance with the Clean AirAct Amendments of 1990 (CAAA).

2. RATE MATTERS:

Rate Activity In November 1993 the IURC granted a

$34.7 million annual rate increase in response to the Company's request for a

$44.8 million increase filed in April 1992.

The new rates include, among other things, recovery of the ongoing amounts being accrued for postretirement benefits other than pensions (OPEB), an increase in the provision for nuclear plant decommissioning costs and the amortization of deferred incremental nuclear plant refueling outage costs.

In October 1993 the MPSC approved a settle-ment agreement that provides for a three-step increase in recovery of nuclear decommissioning costs for the Cook Plant. The first step increase of

$ 1.2 million annually was effective in November 1993.

The second and third steps provide for recoveries to be increased by $ 1 million annually in May 1994 and an additional $ 1 million annually in November 1994.

The MPSC also ordered that a new decommissioning study be filed before Decem-ber 1994.

Unaffjliated Coal and AffiliatedTransportation Cost Recovery In October 1993 the FERC denied a request by a wholesale customer seeking rehearing of a February 1993 order.

The February 1993 order reversed a

1990 administrative law judge's initial decision and dismissed the wholesale customer's complaint concerning the reasonableness of coal costs from an unaffiliated supplier who leased a Utah mining Long-term fuel supply contracts contain clauses for periodic adjustments.

The retail jurisdictions have fuel clause mechanisms that provide with the regulators'eview and approval for deferred recov-ery of changes in the cost of fuel.

The contracts are for various terms, the longest of which extend to 2014, and contain various clauses that would release the Company from its obligation under certain force majeure conditions.

Unit Power Agreements The Company is committed under unit power agreements to purchase 70% of AEGCo's Rockport Plant capacity unless it is sold to unaffiliated utilities.

AEGCo has one long-term contract with an unaffiliated utilitythat expires in 1999 for 455 mw of Rockport Plant capacity.

The Company sells under contract up to 250 mw of Rockport Plant capacity to Carolina Power and Light Company, an unaffiliated utility. The contract expires in 2009.

Litigation An appeal to the Indiana Court of Appeals by a local distribution utility of a 1992 DeKalb County Circuit Court of Indiana decision is pending, The circuit court dismissed the case filed under a

provision of Indiana law that allows the local distri-bution utility to seek damages equal to the gross revenues received by the Company for rendering service in the designated service territory of the local distribution utility.

The Company had re-ceived approximately $29 million in gross revenues from a major industrial customer in the local distri-18

. ~

INDIANAMICHIGANPOWER COMPANy'ND SUBSIDIARIES bution utility's service territory. The case resulted from a Supreme Court of Indiana decision which overruled an appeals court and voided an IURC order which assigned the major industrial customer to the Company.

The Company is involved in other legal proceed-ings and claims.

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

Clean AI'r The CAAArequire significant reductions in sulfur dioxide and nitrogen oxides emitted from various AEP System generating plants.

The law estab-lished a deadline of 1995 for the first phase of reductions in sulfur dioxide emissions (Phase I) and the year 2000 for the second phase (Phase II) as well as a permanent nationwide cap on sulfur dioxide emissions after 1999.

could be incurred in the future to meet the require-ments of new laws and regulations, ifenacted, and to clean up disposal sites under existing legislation.

The Superfund created by the Comprehensive Environmental Response Compensation and Liability Act addresses cleanup of hazardous substance disposal sites and authorizes the United States Environmental Protection Agency (Federal EPA) to administer the cleanup programs.

The Company has been named by the Federal EPA as a "potential-ly responsible party" (PRP) for seven sites and has received information requests for three other sites.

For two of the PRP sites, liability has been settled with little impact on results of operations.

I&M also has been named a PRP at one Illinois site and has received an information request for one Indiana site under analogous state cleanup laws. Although the potential liabilityassociated with each site must be evaluated individually, several general state-ments can be made regarding such potential liabili-The AEP Systemwide compliance plan calls for fuel switching to medium-sulfur coal at I&M's Tanners Creek Unit 4 with minimal capital cost.

The Breed unit which is a Phase I affected unit is scheduled to close on March 31, 1994.

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

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

In addition, a portion of the costs of com-pliance for the AEP System may be incurred through the Power Pool (which is described in Note 5).

If I&M is unable to recover compliance costs from its customers, results of operations and financial condition would b'e adversely impacted.

Whether the Company disposed of hazardous substances at a particular site is often unsubstanti-ated; the quantity of material disposed of at a site was generally small; and the nature of the material generally disposed of was non-hazardous.

Typical-ly, the Company is one of many parties named PRPs for a site and, although liability is joint and

several, at least some of the other parties are generally financially sound enterprises.

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

However, if for unknown reasons, significant costs are incurred for cleanup, results of operations and possibly financial condition would be adversely affected unless the costs can by recovered from insurance proceeds and/or customers, Other Fnvironmental Matters Nuclear Plant The Company and its subsidiaries are regulated by federal, state and local authorities with respect to air and water quality and other environmental matters.

The generation of electricity produces non-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 and will be incurred.

Significant additional costs l&Mowns and operates the two-unit 2,110 mw Cook Plant under licenses granted by regulatory authorities, The operation of a nuclear facility involves special

risks, potential liabilities, and specific regulatory and safety requirements.

Should a nuclear incident occur at any facility in the United States liability could be substantial.

Should nuclear losses or liabilities be underinsured or exceed accumulated

funds, or should rate recovery be

denied, results of operations and financial condition would be negatively affected, Specific information about risk management and potential liabilities is discussed below.

19

Nuclear Insurance Public liability is limited by law to $9.4 billion should an incident occur at any licensed reactor in the United States.

Commercially available insur-ance provides $200 million of this coverage.

In the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be provided by a deferred premium assess-ment of $79.3 million on each licensed reactor payable in annual installments of $ 10 million. As a result, IRM could be assessed

$ 158.6 million per nuclear incident payable in annual installments of

$20 million.

The number of incidents for which payments could be required is not limited.

Nuclear insurance pools and other insurance policies provide $ 2.75 billion of property damage, decommissioning and decontamination coverage for Cook Plant.

Additional insurance provides 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 nuclear units.

The Company could be assessed up to

$24 million under these policies.

Spent Nuclear Fue/ Disposal Federal law provides for government responsibili-ty for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal.

The fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collect-ed from customers and remitted to the U.S. Trea-sury.

Fees and related interest of $ 148 million for fuel consumed prior to April 7, 1983 have been recorded as long-term debt and a regulatory asset.

The regulatory asset is being amortized as rate recovery occurs.

I%M has not paid the government the pre-April 1983 fees due to various factors including continued delays and uncertainties related to the federal disposal program. At December 31, 1993, funds collected from customers to dispose of nuclear fuel and related earnings totalling $ 133 million were held in external funds included in the financial statements as other property and invest-ments.

Decommissioning operate the two nuclear units expire in 2014 and 2017.

After expiration of the licenses the plant is expected to be decommissioned through disman-tling. Estimated decommissioning costs range from

$588 million to $ 1.1 billion in 1991 dollars.

The wide range is caused by variables in the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations which depends on future developments in the federal government's spent nuclear fuel disposal program.

Decommissioning costs are being recovered based on at least the lower end of the range in the cur-rent and prior studies.

I@M records decommission-ing costs in other operation expense and records a noncurrent decommissioning liability equal to the rate recovery which was $ 13 million in 1993, $ 12 million in 1992 and $ 11 million in 1991.

Decom-missioning amounts recovered from customers are deposited in external trusts.

Trust fund earnings increase the fund assets and the recorded liability.

Trust fund earnings decrease the amount to be recovered from ratepayers.

At December 31, 1993, the decommissioning trust fund balance and the accumulated provision for decommissioning were $ 170 million.

In recent rate increases, which are discussed in Note 2, the Company received additional annual amounts forthe decommissioning ofthe Cook Plant of $ 10 million in its Indiana jurisdiction and 03.2 million phased-in in its Michigan jurisdiction.

4. 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, 1993,

$5.9 million of retained earnings were restricted.

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

In 1993, I%M's parent made a cash capital contribution of $ 10 million.

Also in 1993 S1.2 million, representing the issuance costs for three series of cumulative preferred stock, was charged to paid-in capital, There were no other transactions affecting the common stock or paid-in capital accounts in 1993, 1992 or 1991.

Decommissioning costs are accrued over the service life of the Cook Plant.

The licenses to 20

tINDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

5. RELATED PARTY TRANSACTIONS:

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

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

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

Operating revenues include

$204.6 million in

1993,

$ 154.1 million in 1992 and $204.8 million in 1991 for supplying energy and capacity to the Power Pool.

Purchased power expense includes charges of $ 20.9 million in 1993,

$ 82.6 million in 1992 and

$24.6 million in 1991 for energy 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 was included in operating reve-nues in the amount of $ 57 million in 1993,

$45.8 million in 1992 and $ 65.5 million in 1991.

recorded in other operation expense for transmis-sion services in 1993, 1992 and 1991, respective-ly.

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

Year Ended Oecemb r

~993

~9

~9 (in thousands)

Affiliated Companies

$25,372

$24,753

$23,863 Unafflllated Cempanlea 1 717 3 964 4

641 Total

~27 089

~28 717

~28 604 American Electric Power Service Corporation (AEPSC) provides certain managerial and profes-sional services to AEP System companies.

The costs of the services are determined by AEPSC on a direct-charge basis to the extent practicable and on reasonable bases of proration for indirect costs.

The charges for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co Inc.

Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered.

AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.

In addition, the Power Pool purchases power from unaffiliated companies for immediate resale to other unaffiliated utilities. The Company's share of these purchases was included in purchased power expense and totaled

$ 5.1 million in 1993,

$6.5 million in 1992 and $ 13.7 million in 1991.

Reve-nues from these transactions are included in the above Power Pool wholesale sales.

The cost of power purchased from AEGCo, an affiliated company that is not a member of the Power Pool, was included in purchased power expense in the amounts of $78.9 million, $88 million and $83 million in 1993, 1992 and 1991, respectively.

The Company operates the Rockport Plant and bills AEGCo for its share of operating costs.

AEP System companies participate in a 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, credits of

$47.4

million,

$48.2 million and

$46.2 million were

6. 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.

Effective January 1, 1992 employees may retire without reduction of benefits at age 62 and with reduced benefits as early as age 55. Pension costs are allocated by first charging each System compa-ny with its service cost and then allocating the remaining pension cost in proportion to its share of the projected benefit obligation. The funding policy is to make annual trust fund contributions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum contribution required by law.

Net pension costs for the years ended December 31, 1993, 1992 and 1991 were $4.7 million, $5.6 million and $2.3 million, respectively.

21

2

~

)

~

An employee savings plan is offered which allows participants to contribute up to 16% of their salaries into three investment alternatives, including AEP Co.,

Inc. common stock.

The Company contributes an amount equal to one-half of the first 6%

of the employees'ontribution.

The Company's contribution is invested in AEP Co., Inc.

common stock and totaled 83.5 million in 1993, 83.3 million in 1992 and $3.1 million in 1991.

The AEP System provides certain other benefits for retired employees under an AEP System other postretirement benefit plan.

Substantially all employees are eligible for health care and life insurance benefits if they have at least 10 service years and, effective January 1, 1992, are age 55 at retirement.

Prior to 1993, net costs of these benefits were recognized as an expense when paid and totaled 82.7 million and 82.6 million in 1992 and 1991, respectively.

SFAS

106, Employers'ccounting for Postretirement Benefits Other Than Pensions, was adopted in January 1993.

SFAS 106 requires the accrual of the present value liabilityfor the cost of postretirement benefits other than pensions (OPEB) during the employee's service years.

Prior service costs are being recognized as a transition obligation over 20 years in accordance with SFAS 106.

OPEB costs are based on actuarially-determined stand alone costs for each System company.

The funding policy is to contribute incremental amounts recovered through rates and cash generated by the corporate owned life insurance (COLI) program.

The annual accrued costs for 1993 required by SFAS 106 for employees and

retirees, which includes the recognition of one-twentieth of the prior service transition obligation, was

$ 12.4 million.

The Company received approval from the IURC to recover the increased OPEB costs.

In the Michigan and wholesale jurisdictions, the Company received authority to defer the increased OPEB costs which are not being currently recovered in rates.

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

At December 31, 1993, 86.2 million of incremental OPEB costs were deferred.

7. SUPPLEMENTARY INFORMATION:

Year Ended December 31

~993

~99

~9 (in thousands)

Taxes other than federal income taxes include:

Real and Personal Property State Gross Receipts, Excise, Franchise and Hiscellaneous State and Local Payroll State Income Total

$35 683

$359818

$339265 15,179 15,902 8,911 8,075

~28

~554

~62 189

~62 783 15,008 9,001

~82 6

~67 978 Cash was paid for:

Interest (net of capitalized amounts)

$82,509 Income Taxes 68,303

$84,691 15,285

$84,581 73,694 Noncash acquisitions under capital leases were 15,467 47,905 25,624 To reduce the impact of adopting SFAS 106, management took several measures.

First, a

Voluntary Employees Beneficiary Association (VEBA) trust fund for OPEB benefits was estab-lished.

A 84.3 million advance contribution was made to the trust fund in 1990, the maximum amount deductible for federal income tax purposes.

In 1993, a $700,000 contribution was made to the VESA trust fund from amounts recovered from ratepayers.

In addition, to help fund and reduce the future costs of OPEB benefits, a COLI program was implemented, except where restricted by state Iaw. The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, as other property and investments.

The policies generated cash of 8600,000 in 1993,

$ 1,700,000 in 1992 and

$700,000 in 1991 inclusive of related tax benefits which was contributed to the VEBAtrust fund.

In 1997 the premium will be fully paid and the cash generated by the policies should increase signifi-cantly.

22

INDIANAMICHIGANPOWER COhrPANY AND SUBSIDIARIES

8. FEDERAL INCOME TAXES:

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

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 1993

$ 93,974 (50,959)

~0308) 34 707 6,026 1,054

~235) 6 045

~47 55 Year Ended December 31

~199 (in thousands)

$ 9,122 25,405

~9020) 25 499 1,569 4,492

~645) 5 416

~30 915

~99

$ 73,702 (18,793)

~0435) 46 474 3,348 (3,084)

~753)

~409)

~45 905 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.

Net Income Federal Income Taxes Pre-tax Book Income Federal Income Tax on Pre-tax Book Income at Statutory Rate (35K in 1993 and 34K in 1992 and 1991)

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

Removal Costs Adoption of SFAS 109 Investment Tax Credits (net)

Corporate Owned Life Insurance Other Total Federal Income Taxes as Reported Effective Federal Income Tax Rate 1993

$ 129,313 41 552

~770 065

$59,803 (2,632) 5,271 (8,543)

(4,697)

~7650)

~41 552 24.3X Year Ended December 31

~199 (in thousands)

$ 123,948 3D 915

~754 063

$ 52,653 (3,042)

(9,011)

(4,402)

~5203 )

~30 915 20.0X

~99

$ 136,932 45 985

~702 917

$62,192 (2,259)

(9,087)

(3,044)

~)0) 7)

~45 905 25.IX 23

The following are the principal components of federal income taxes as reported:

Year nded December 31 Current:

Federal Income Taxes Investment Tax Credits Total Current Federal Income Taxes Deferred:

Depreciation Unrecovered and Levelized Fuel Nuclear Fuel Deferred Return - Rockport Plant Unit 1

Deferred Net Gain - Rockport Plant Unit 2 Levelized Nuclear Refueling Costs Accrued Interest Income Adoption of SFAS 109 Other Total Deferred Federal Income Taxes Total Deferred Investment Tax Credits Total Federal Income Taxes as Reported 1993

$ 100,000 100 000 (12,167)

(13,795)

(3,271)

(2,644) 3,922 (11,488)

(3,854) 5,271

~)) 079)

~49 905)

~0543)

~4) 552

~199 (in thousands)

$ 10,029

~66 10 691 (8,356) 11,729 5,410 (2,772) 4,230 16,048 3,854

~246) 29 097

~9673)

~30 915

~99

$ 76,949

~0 77 050 (6,969)

(670)

(6,484)

(2,864) 3,098

~7900)

~2) 077)

~9108)

~45 965 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 and investment tax credits utilized to the System companies giving rise to them in determin-ing their current tax expense.

The tax loss of the System parent company, AEP Co48 Inc48 is allocated to its subsidiaries with taxable income.

With the exception of the loss of the parent company, the method of allocation approximates a

separate return result for each company in the consolidated group.

Deferred Tax Asset (Liability)

(in thousands)

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

Total Net Deferred Tax Liability

$ (494,966)

(100,432) 62,761

~21 203)

~553 920)

The net deferred tax liabilityof $553.9 million at December 31, 1993 is composed of deferred tax assets of $233.4 million and deferred tax liabilities of

$787.3 million.

The significant temporary differences giving rise to the net deferred tax liability are:

The AEP System settled with the Internal Reve-nue 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.

24

48 INDIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES

9. LEASES:

Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs.

The majority of the leases have purchase or renewal options and willbe renewed or replaced by other leases.

Operating Leases Amortization of Capital Leases Interest on Capital Leases Total Rental Payments (in thousands)

$ 103,884

$ 109,466

$ 101,013 46,063 24,124 54,528 8 873 7 473 9 907

~750 020

~747 063

~765 440 Lease rentals are generally charged to operating expense in accordance with rate-making treatment.

The components of rentals are as follows:

Year Ended December 31 Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.

Hon-Cancelable Capital Operating

~eases

~eases (in thousands) 1994 1995 1996 1997 1998 Later Years

$ 9,380 8,574 7,601 6,889 6,257 30 303 98,667 98,203 97,885 96,029 91,118

~20 70 Total Future Hinimum Lease Payments 77,084(al

~2493 603 Less Estimated Interest Elnnent

~23 99 Future minimum lease rentals consisted of the following at December 31, 1993:

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

Oecember 31 1993 1992 (in thousands)

Estimated Present Value of Future Minimum Lease Payments Unamortized Nuclear Fuel Total 53,092 45 661

~90753 Electric UtilityPlant:

Production Oistribut,ion General:

Nuclear Fuel (net of amortization)

Other Total Electric Utility Plant Accumulated Amortization Het Electric Utility Plant Other Property Accumulated Amortization Het Other Property Het Properties under Capital Lease Obligations under Capital Leases Less Portion Oue Mithin One Year Noncurrent Liability 8,033 14,717 45,661 40410 116,829 27 359 89 470 11,269 1 906

~903 98 753

$ 98,753 20 505

~70 160

$ 11,407 14,702 84,208 46 494 156,811 30 630 6

81 2,327 1 819 500 126 689

$ 126,689 32 745

~93 944 (a) Hinimum lease rentals do not include nuclear fuel rentals.

The rental payments are based on the heat produced plus carrying charges on the unamortized nuclear fuel balance.

25

10. CUMULATIVEPREFERRED STOCK:

At December 31, 1993, 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.

The Company issued 350,000 shares of 6.30% Cumulative Preferred Stock Subject to Mandatory Redemption, par value $ 100, on February 8, 1994 and redeemed 350,000 shares of 7.76% Cumulative Preferred Stock Not Subject to Mandatory Redemption, par value $ 100, on February 14, 1994.

A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:

Series Call Pr ice December 31, 1993 Par Value Number of Shares Redeemed Year Ended December 31 Shares Outstanding December 31 1993 Amount December 31 1993

~199 1991 (in thousands) 4-1/8X 4.56K 4.12K 7.08K 7.76K 8.68K

$2.15

$2.25

$ 106.125 102 102.728 101.85 102.28

$ 100 100 100 100 100 300,000 1,600,000 1,600,000 120,000 60,000 40,000 300,000 350,000

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

~87 000

$ 12,000 6,000 4,000 30,000 35,000, 30,000 40,000 40 000

~197 000 B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Series(a) 5.90X (b) 6-1/4X(c) 6-7/8X(d)

Par Value

$ 100 100 100 Shares Outstanding December 31 1993 400,000 300,000 300,000 Amount December 31 1993 1992 (in thousands)

$ 40,000 30,000 30 ODD 100 000 ia) Not callable until after 2002. There aro no aggregate sinking fund provisions through 2002.

lb) Shares issued November 1993. Commencing in 2004 and continuing through tho year 2008, a sinking fund for tho 5.90% cumulative preferred stock willrequire the redemption of 20,000 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at S100 per share.

lc) Sharos issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund for the 8-1/4% cumulative preferred stock will require the redemption of 15,000 shares each year and tho redemption of the remaining shares outstanding on April 1, 2009, in each case at S100 por share.

ld) Shares issued February 1993. Commencing in 2003 and continuing through the year 2007, a sinking fund for the 6-7/8% cumulative preferred stock will require tho redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at Sloo por share.

26

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES 11.

LONG-TERM DEBT AND LINES OF CREDIT:

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

Decenber 31 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.

First Mortgage Bonds Installment Purchase Contracts Other Long.term Debt (a)

Notes Payable to Banks Sinking Fund Debentures 307,823 147,810 40,000 6 053 308,333 143,321 40,000 6 053 1993

~199 (in thousands) 571,468 713,916 Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows:

December 31 1993

~99

{in thousands) 1,073,154 1,211,623 Loss Portion Due Within Ono Year 42 90 Total

~)073 154

~))60 721 (a) Nuclear Fuel Disposal Costs including interest accrued.

See Note 3.

o Rate 4-3/8 7-7/8 9-1/8 7

7.30 8-7/8 7.60 7.70 6.80 6.55 6.10 8-3/8 9-1/2 8-3/4 9.50 9.50 9.50 8.75 8.50 7.80 7.35 7.20 unamor Due 1993. August 1

1997 - February 1

1997 - July 1

1998 - May 1 1999 - December 15 2000- April 1 2002 - November 1

2002 - December 15 2003-July 1

2003

~ October 1

2003

~ November 1

2003 - December 1

2008 - March 1

2017 - February 1

2021 - May 1 202'I - May 1 2021 - May 1 2022-May 1 2022 - December 15 2023 - July 1

2023 - October 1

2024-February 1

tized Discount (net)

Less Portion Due Within One Year 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

~353

)

571,468

$ 42,902 50,000 75,000 35,000 35,000 50,000 50,000 40,000 40,000 34,034 100,000 10,000 10,000 20,000 50,000 75,000

~30 0) 713,916 42 902 Total 571 468

~67) 014 First mortgage bonds outstanding were as fol-lows:

December 31 1993 1992

{in thousands)

~Rate Due City of Lawrenceburg, Indians:

7 200B - May 1 B-7/8 2006 - May 1 7

2015-Apnl 1 5.9 2019 - November 1

City of Rockport, Indiana:

9-1/4 2014 - August 1

B-3/4(a) 2014 - August 1 (b) 2014-August 1 7.6 201B - March 1 City of Sullivan, Indiana:

7-3/8 2004 - May 1 6-7/8 2006 - May 1 7-1/2 2009 - May 1 5.95 2009 - May 1 unamortized Discount 25,000 52,000 50,000 50,000 50,000 40,000 45,000

~4177)

$ 40,000 12,000 25,000 50,000 50,000 50,000 40,000 7,000 25,000 13,000

~3667)

Total

~307 023

~308333 (a) The adjustable interest rate changed on August 1, 1990 and willchange every five years thereafter.

(b) The variable interest rate is determined weekly. The average weighted intorest was 3.0% in 1993 and 3.7% for 1992.

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

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

Accordingly, the installment purchase contracts have been classified for repayment purposes based on their next interest rate adjustment date.

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

27

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

At December 31, 1993, annual long-term debt

payments, excluding premium or discount, are as follows:

Princi al Amount (in thousands) 1994 1995 1996 1997 1998 Later Years Total 140,000 41,053 899 810 1 080 863 The sinking fund debentures are due May 1, 1998 at an interest rate of 7-1/4%.

Prior to December 31, 1993, sufficient principal amounts of debentures had been reacquired in anticipation of all future sinking fund requirements.

Additional debentures of up to

$300,000 may be called annually.

December 31, 1993 and 1992 fair values for external trust funds were $321 million and $270 million and carrying values were $303 million and

$262 million, respectively.

Fair values for long-term debt were

$ 1.1 billion and

$ 1.2 billion at December 31, 1993 and 1992, respectively.

Fair value at December 31, 1993 for preferred stocks subject to mandatory redemption, which were issued in 1993, was $99 million.

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

External trust funds are used to accu-mulate funds collected from customers for future nuclear liabilities and are reported on the balance sheet as other property and investments.

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

13. UNAUDITED QUARTERLY FINANCIALINFOR-IVIATION:

Short-term debt borrowings are limited by provi-sions of the 1935 Act to $200 million and further limited by charter provisions to $ 127 million. Lines of credit are shared with AEP System companies and at December 31, 1993 and 1992 were avail-able in the amounts of $ 537 million and

$ 521

million, respectively.

Commitment fees of approximately 3/16 of 1% a year are paid to the banks to maintain the lines of credit.

12.

FAIR VALUEOF FINANCIALINSTRUMENTS:

quarterly Periods Ended 1993 Harch 31 June 30 September 30 Oecember 31 1992 Harch 31 June 30 September 30 Oecember 31 301,134 280,421 311,080 304,120 54,022 35,035 43,535 24,844 45,323 24,384 52,640 39,685 Operating Operating Net Revenues Income Income (in thousands)

$302,968

$53,269

$28,522 278,100 40,722 21,397 320,409 52,898 33,658 301,166 63,031 45,736 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.

At Fourth quarter 1992 net income includes

$ 13 million comprised of interest on prior years'ederal income tax refunds and cost reductions due to favorable benefit plans experience.

28

INDIAAIAMICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS 1993 1992 1991 990

~989 OPERATIN6 REVENUES (in thousands):

Retail:

Residential:

'Without Electric Heatin9 With Electric Heating Total Residential Co()n)ercial industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Revenues from Energy Sales Provision for Refunds of Revenues Collected in Prior Years Total Net of Provision for Refunds Other Total Operating Revenues 205,315 97 560 302,883 220,938 250,939 5 593 780,353 404 910 209,682 90 553 308,235 228,285 267,643 11 012 815,175 369 379 206,257 93 209 299,546 216,303 241,858 12 120 769,827 436 003 192,822 00 710 281,540 205,025 244,773 ll 799 743,137 510 000 1,185,263 1,184,554 1,205,910 1,261,217 1,184,508 10 135 1,180,516 16 239 1,211,086 14 701 1,256,041 15 473 1 202 643 1

196 755

~l225 867 1

271 514

~755)

~4038) 5 176

~5176) 195,504 95 987 291,491 205,918 251,279 12 021 760,709 361 962 1,122,671 1,122,671

~)135 507 SOURCES ANO SALES OF ENER6Y (in millions of kilowatt-hours):

Sources:

Net Generated:

Fossil Fuel Nuclear Fuel Hydroelectric Total Net 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 Comercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Sales 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

~11 731

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

~5237 32,979

~454

~31 525 3,166

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

~17 393

~31 525 14,451 11,115

~17 25,693

~7983 33,676

~1633

~32 043 2,955

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

~18 346

~32 043 10,634 12,094

~08 22,836

~7630 30,466

~1647

~28 819 2,975

~1627 4,602 3,519 5,512 236 13,869

~14 950

~28 819 29

OPERATING STATISTICS (Concluded)

AVERAGE COST OF FUEL CONSUMED (in cents):

Per Million Btu:

Coal Nuclear Overall Per Kilowatt-hour Generated:

Coal Nuclear Overall 1993 130 36 72 1.27

.40

.77 992 136 54 103 1.34

.61 1.08

~99 141 48 84 1.39

.53

.91 1990 145 58 105 1.42

.64 1.08 164 61 106 1.62

.67 1.11 RESIDENTIAL SERVICE - AVERAGES:

Annual Kwh Use per Customer:

Total With Electric Heating Annual Electric Bill:

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

Total With Electric Heating 10,564 17,989

$ 655.07

$ 1,028.82 6.20 5.72 10,107 17,513

$672.31

$ 1,056.91 6.65

6. 04 10,539 17,703

$659.01

$ 1,016.24 6.25 5.74 9,944 16,897

$624.95

$983.28 6.28 5.82 10,303 18,337

$652.64

$1,081.78 6.33 5.90 NUMBER OF CUSTOMERS:

Year-End:

Retail:

Residential:

Without Electric Heating With Electric Heating Total Residential Co2nnercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)

Total Customers 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

~575 428 362,645 91 179 453,824 50,994 4,801 2 160 511,779 55 511 834 360,040 89 881 449.921 50,043 4,792 2

168 506,924

~5 506 975 30

DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED STOCK By Quarters (1993 and 1992)

CUMULATIVE PREFERREO STOCK 1st 1993 -

uarters 2nd 3rd 4th 1st 1992 -

uarters hand 3rd 4th

($ 100 Par Value) 4-1/BX Series Oividends Paid Per Share Harket Price - $ Per Share (MSE)

- High

- Low

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

$ 1.03125

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

Ask (high/low)

Bid (high/low)

4. 12K Series Oividends Paid Per Share Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High

- Low 5.90K Series (a)

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

Ask (high/low)

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

Oividends Paid Per Share Harket Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low)

$ 1.03

$ 1.03

$ 1.03

$1.03 51 48 51-1/2 48 55-1/4 51 58-1/2 54-3/4

$0.9342

$0.5382

$ 1.14

$ 1.14

$ 1.14

$ 1.14

$ 1.03

$ 1.03

$1.03

$ 1.03 47 47 39-1/2 47 48 47 50 48

$ 1.14

$ 1.14

$ 1.14

$ 1.14 6-7/BX Series (b)

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

Ask (high/low)

Bid (high/low)

$.84

$ 1.71875

$ 1.71785

$ 1.71875 7.08K Series Oividends Paid Per Share Market Price - $ Per Share (NZSE) - High

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

$ 1.77

$ 1.77

$ 1.77

$ 1.77 88-1/2 83-1/4 88-1/2 84-1/2 92 85-1/2

$ 1.77

$ 1.77

$ 1.77

$ 1.77 92 89 7.76K Series (c)

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

- High

- Low 102-1/4 95-3/4 102 98 104 100 102-3/4 98-1/2

$ 1.94

$ 1.94

$ 1.94

$ 1.94 95-3/4 90-1/2 96-1/8 92-1/4 98-3/4 93-1/2 98-1/4 93

$ 1.94

$ 1.94

$ 1.94

$ 1.94 31

DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED'TOCK By Quarters (1993 and 1992) (Concluded)

CUHU ATIV PR FERR 0 STOCK 1st 1993 -

uar ters 3rd 4th 2nd 1992 -

uarters gnd

~rd 4th

($ 100 Par Value) 8.6N Series (d)

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

- Low

$2.17

$2.17

$2.17

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

$2.17 102-1/4 98-1/2

$2.17

$2.17

$2.17 102 103 103 99 100-1/4 100

($25 Par Value)

$2.15 Series (e)

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

- Low 27-1/2 27-1/4 27-3/8 26 26-1/4 25-3/4 26-1/2 25-5/8 26 25 26 25 27-1/4 27 25-3/8 25-1/2

$0.5375

$0.5375

$0.5375

$0.2628

$0.5375

$0.5375

$0.5375

$0.5375

$2.25 Series (f)

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

- Low

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

$0.5625

$0.5625

$0.5625

$0.5625 27-1/4 27-1/4 27-1/2 27-1/4 26 25-7/8 26 25-3/4 HSE

- Hldwest Stock Exchange OTC

- Over-the-Counter NYSE - New York Stock Exchange Note - The above bid and asked quotations represent prices between dealers Harket quotations provided by National Ouotation Bureau, Inc.

Dash indicated quotation not available.

(a) Issued November 1993 (b) Issued February 1993 (c) Called for redemption and refinanced in February 1994 (d) Redeemed December 1993 (e) Redeemed November 1993 (f) Redeemed March 1993 and do not represent actual transactions.

32

.0 NDIANAMICHIGANPOWER 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 FORM 10-K ANNUALREPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1994 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 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 LAKE ERIE OHIO INDIANA WEST VIRGINIA KENTUCKY VIRG I NIA Indiana Michigan Power Co. area Other AEP operating companies'reas Major power plant TENNESSEE IB+

prinied on recycled paper

ENCLOSURE 2 TO AEP:NRC:0909J INDIANAMICHIGAN POWER COMPANY'S PROJECTED CASH FLOW

Indiana Michigan Power Co.

1994 Forecasted Sources and Uses of Funds Based on Forecasted Case 9450

$ Millions Projected 1994 Net Income AfterTaxes Less Dividends Paid 138.4 118.3 Retained Earnings Adjustments:

Depreciation And Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Other 20.1 162.0 (23.1)

(28.4)

(2.3)

(7.7)

Total Adjustments 100.5 Internal Cash Flow 120.6 Average Quarterly Cash Flow 30.2 Average Cash Balances and Short-Term Investments 1.9 Total 32.1