ML17331B339

Indiana Michigan Power Company 1993 Annual Rept. W/Projected Cash Flow for 1994 & 940406 Ltr

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 "i ~ ~

REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9404130143 DOC.DATE: /~+53. NOTARIZED: NO FACIL:50-315 Donald C. Cook Nuclear Power Plant, Unit 1, Indiana M 05000315 DOCKET 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 D DISTRIBUTION CODE M004D COPIES RECEIVED:LTR ENCL SIZE:

TITLE: 50.71(b) Annual Financial Report NOTES:

RECIPIENT C OPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD3-1 LA 1 1 PD3-1 PD 1 1 D HICKMAN,J 1 1 INTERNAL: AEOD/DOA 01 1 1 EXTERNAL: NRC PDR 1 1 R

D D

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Indiana Michigan Power CompaIy

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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 INDIANA MICHIGAN 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 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 ADOCK .'05000315' I ('

PDR PDR.',,

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

0 1993 Annual Report

CONTENTS 0 ~ ~

Background ... ~ 0 ~ ~ ~ 0 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1 Directors and Officers ~ ~ ~ ~ ~ ~ ~ \ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 2 Selected Consolidated Financial Data ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ \ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 3 Management's Discussion and Analysis of Results of Operations and Financial Condition.......... 4-9 Independent Auditors'eport.... ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ o 10 Consolidated Statements of Income ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1 1 Consolidated Balance Sheets .. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 12 13 Consolidated Statements of Cash Flows 14 Consolidated Statements of Retained Earnings . .... 15 Notes to Consolidated Financial Statements .........,......................... 16-28 Operating Statistics ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

Dividends and Price Ranges of Cumulative Preferred Stock ~ ~ ~ ~ ~ ~ ~ 31 32

t INDIANAMICHIGANPOWER COMPANY AIVD SUBSIDIARIES One Summit Square, p.O. Box 60, Fort Wayne, indiana 46801 BACKGROUND INDIANAMICHIGANPOWER COMPANY (the Company) is engaged in the generation, purchase, transmission and distribution of electric power 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 utility subsidiaries 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 William J. Lhota Peter J. DeMaria Gerald P. Maloney Richard E. Disbrow (a) Richard C. Menge William N. D'Onofrio Ronald E. Prater (d)

A. Joseph Dowd (b) David B. Synowiec (d)

E. Linn Draper, Jr. Dale M. Trenary (c)

Allen R. Glassburn (c) William E. Walters OFFICERS Richard E. Disbrow (a) Gerald P. Maloney Chairman of the Board and Chief Executive Officer Vice President E. Linn Draper, Jr. (b) James J. Markowsky (f)

Chairman of the Board and Chief Executive Officer Vice President Richard C. Menge John F. DiLorenzo, Jr.

President and Chief Operating Officer Secretary Mark A. Bailey Elio Bafile Vice President Assistant Secretary and Assistant Treasurer Peter J. DeMaria Jeffrey D. Cross Vice President and Treasurer Assistant Secretary William N. D'Onofrio Carl J. Moos Vice President Assistant Secretary A. Joseph Dowd John B. Shinnock Vice President Assistant Secretary Eugene E. Fitzpatrick Leonard V. Assante Vice President Assistant Treasurer Richard F. Hering (e) Bruce M. Barber Vice President Assistant Treasurer William J. Lhota Gerald R. Knorr Vice President Assistant Treasurer As of January 1, 1994 the current directors and off(cars of Indiana 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 (dl Elected Apnt 27, 1993 (bl E(ected Apn7 28, 1993 (el Rex'gned Juty 1, 1993 (cl Ree'gned Apn7 27. 1993 (/1 Elected Juty 1, 1993

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Selected Consolidated Financial Data rEn D m

~1 (in thousands)

INCOME STATEMENTS DATA:

Operating Revenues $ 1,202,643 $ 1,196,755 S1,225,867 01,271,514 01,135,587 Operating Expenses ~992 72 ~1Q)~12 ~1(~7~2 ~~~21 g4 Operating Income Nonoperating Income (Loss)

Income Before Interest Charges

~24 209,920 209,686 i ~ts 195,520 11 209,635

~72 ~77 227,289 223,568 1

201,491 209,048

~~27 213,983 246,720 Interest Charges ~80 37 tL5 687 ~636 9~7 ~1~74 Net Income Preferred Stock Dividend Requirements Earnings Applicable to Common Stock 4 129,313

~14 22 ~141 7 115 088 ~108 123,948 531

~tet

~l21 136,932 515 7 ~17

~102 118,391 804 139,237 1~4 121 18 m r 1 199 1992 ~11 BALANCE SHEETS DATA: (in thousands)

Electric Utility Plant $ 4,290,957 $ 4,266,480 04,135,820 S4,066,227 03,969,602 Accumulated Depreciation and Amortization 1714 l72 ~1'1~14 [ ~12~14 ~l421 2 ~F8,~7 Net Electric Utility Plant ~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 791,517 S 782,741 0 782,741 0 782,741 0 782,741 Retained Earnings 177tftt 17~1 ~1~24 1'i~4[ ~12 21 Total Common Shareowner's Equity 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 $ 197,000 197,000 197,000 197,000 Subject to Mandatory Redemption (b) M1LQK Cumulative Preferred Stock ~1871~9'otal 000 ~197 000 ~197 000 ~197 00 ~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 critical factors and to take advantage of the oppor-tunities increased competition will bring.

Net income increased 4.3% in 1993 and de-creased 9.6% in 1992. The scheduled refueling of Operating Revenues and Energy Sales the two nuclear generating units and an unsched-uled outage at one of the units in 1992 required Operating revenues increased $ 6 million in 1993 the purchase of more expensive replacement power following a decline of $ 29 million in 1992. The from the AEP System Power Pool (Power Pool) and 1993 increase and the 1992 decrease were attrib-reduced wholesale sales to the Power Pool reduc- utable to the Donald C. Cook Nuclear Plant (Cook ing net income in 1992. The return to service of Plant) generating units being out of service for the nuclear units along with the retirement and the scheduled refueling and maintenance and an un-refinancing of debt at lower interest rates was scheduled outage in 1992 which reduced the responsible for the increase in net income in 1993. amount of energy the Company had available for sale to the Power Pool.

Outlook The changes in revenues can be analyzed as The electric utility industry is expected to follows:

undergo significant changes for the remainder of Increase (Decrease) the decade because of increasing competition in From Previous Year ~

dollars in millions the generation and sale of electricity and increasing energy flows resulting from open transmission Retail:

1993

~unt ~ 1992

~un access. Although management believes that the Price variance $ (75.1) $ 42.3 Company is well positioned, as a low cost produc- Volume variance

~34.6) (4.3)

~345 3 5.9 er, to compete, efforts will continue to further Wholesale:

reduce costs and increase effectiveness. Price variance (137.2) 75.2 Volume variance 172.7, ~(41 )

The Company faces additional challenges from 35. 5 9.6 ~66.7)(15.3) compliance with the Clean Air Act Amendments of Othev Opevetln9 Revenues 5.2 ~7.7) 1990, other environmental concerns and costs, the Total ~5. 9 0.5 ~29.() (2.4) cost of operating, maintaining and eventually decommissioning the two nuclear generating units The unfavorable retail and wholesale price and the disposal of their spent nuclear fuel that variances in 1993 reflect the operation of fuel and could affect financial performance and possibly the power supply cost recovery mechanisms due to the ability to meet financial obligations and commit- availability of the Cook Plant and lower average ments. While management believes the Company cost generation. Under the retail jurisdictional fuel is equipped to meet these challenges, future finan- clauses, revenues were accrued in 1992 for future cial performance is heavily dependent on the ability recovery of higher cost replacement power during to obtain favorable rate-making treatment to recov- the nuclear outages.

er costs of service on a timely basis.

The increase in 1993 retail sales volume re-Future results of operations will be affected by flects continuing improvement in industrial sales, a several factors, including the continued economic return to normal weather and moderate growth in health of our service territory, the weather, compe- residential and commercial customer classes. The tition for wholesale sales, new environmental laws increase in wholesale sales volume in 1993 result-and regulations and the rate-making policies of the ed from the increased availability of energy for Company's regulators. Many of these factors are delivery to the Power Pool due to availability of the not generally within management's direct control Cook Plant as well as increased sales by the Power yet every effort will be made to work with regula- Pool to unaffiliated utilities which the Company tors, government officials, and current and pro- shares as a member of the Pool.

spective customers to positively influence these

t INDIANAMICHIGANPOWER COMPANV AND SUPSIDIARIES The substantial retail and wholesale price vari- The decline in purchased power expense in 1993 ance in 1992 resulted from recovery of higher reflects a reduced level of energy receipts from the fossil fuel generation costs and power pool pur- Power Pool because of the increased availability of chases which were incurred during the Cook Plant the nuclear units and reduced power purchases outages. The reduction in 1992 wholesale sales from AEP Generating Company as a result of volume reflects a decrease in sales to the Power Rockport Plant maintenance outages. The increase Pool because of the Cook Plant outages and re- in purchased power expense in 1992 was the duced wholesale sales by the Power Pool, Efforts result of an increased level of energy receipts from to improve short-term wholesale sales are affected the Power Pool during the nuclear outages.

by the highly competitive nature of the short-term energy market and other factors such as unaffiliat- Certain other operation and maintenance proce-ed generating plant availability, the weather and dures can be performed only when a nuclear unit is the economy, that are not generally within out of service. Therefore, during the 1992 nuclear management's control Future results of operations

~ refueling outages, significant other operation and will be affected by the ability to make cost-effec- maintenance expenses were incurred. However, tive wholesale sales or, if such sales are reduced, the impact on 1992 earnings from refueling outag-the ability to timely raise retail rates. es was mitigated through the implementation of levelized accounting in 1992. Levelized accounting Operating Expenses Decline spreads the incremental cost of refueling outages so that the cost of an average number of refuelings Changes in the components of operating ex- are reflected in each year's expenses. The Compa-penses were as follows: ny received regulatory approval to defer incremen-tal nuclear refueling outage costs and to amortize Increase (Oecrease) them from the start of an outage until the begin-From Previous Year ning of the next outage. As a result, 1993 operat-dollars in millions 1993

~unt ~ 1992

~unt ing expenses include the amortization of $ 35.2 million of incremental nuclear refueling outage Fuel $ 26.4 13.6 $ (57.5) (22.9) expenses that were deferred in 1992.

Purchased Power (72.0)(40.0) 57.8 47.1 Other Operation 12.6 5.0 5.0 2.0 Maintenance 4.9 3.5 18.5 15.6 Taxes other than federal income taxes in-Depreciation and creased in 1993 primarily due to a substantial Amortization 5.4 4.1 1.1 0.8 increase in Indiana supplemental net income tax Amortization of Rockport because the nuclear refueling outage costs incurred Plant Unit I Phase-in Plan Oeferrals (0.7) (4.0) (0.7) (3.9) in 1992 were tax deductible in that year. There Taxes Other Than were no refueling outages in 1993. Federal income Federal Income Taxes 5.7 9.2 (0.6) (0.9) taxes attributable to operations increased in 1993 Federal Income Taxes ~9. 36. I ~20.9) (45.1) due to an increase in pre-tax operating income and Total ~8.5) (0.9) ~2.7 0.3 a reduction in interest charges. The decline in Fuel expense increased in 1993 due to the federal income taxes attributable to operations in significant increase in nuclear generation and a 6% 1992 reflects a decrease in pre-tax operating increase in fossil generation, partially offset by a income, 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.

Nonoperating Income and Financing Costs Decline Construction Spending Nonoperating income declined in 1993 due to Gross plant and property additions were $ 125 the implementation of Statement of Financial million in 1993 and $ 176 million in 1992. Manage-Accounting Standards No. 109, Accounting for ment estimates construction expenditures for the Income Texes, the recordation in 1992 of interest next three years to be $ 410 million. The funds for income on federal income tax refunds in connection construction of new facilities and improvement of with the settlement of audits of prior years'ax existing facilities come from a combination of returns and the reversal of a provision in 1992 as internally generated funds, short-term and long-a result of the successful settlement of a coal term borrowings and investments in common royalty dispute with the state of Utah. equity by the Company's parent, American Electric Power Company, Inc. (AEP Co., Inc.).

Interest expense declined in 1993 due to the Approximately 92% of the construction expendi-retirement of $ 142 million of long-term debt and tures for the next three years will be financed the refinancing of $ 150 million of long-term debt internally with the remainder financed externally.

and $ 97 million of installment purchase contracts (IPC) at lower interest rates. The decline in 1992 Capital Resources was largely attributable to the refinancing of $ 25 million of IPCs and a lower average interest rate on The Company generally issues short-term debt a variable rate IPC. to provide for interim financing of capital expendi-tures that exceed internally generated funds. At Accrued Utility Revenues and Taxes Accrued December 31, 1993, unused short-term lines of credit of $ 537 million shared with other AEP At December 31, 1992 under retail fuel and System companies were available, Short-term power supply cost recovery mechanisms, $ 38 borrowings increased by $ 5.9 million in 1993. A million of fuel revenues were accrued related to charter provision limits short-term borrowings to fuel and replacement power costs incurred during $ 127 million. Periodic reductions of outstanding the nuclear unit outages. Both retail jurisdictions short-term debt are made through issuance of long-approved recovery. Recovery was completed in term debt and preferred stock and through equity the Indiana jurisdiction and substantially completed capital contributions by the parent company.

in the Michigan jurisdiction in 1993 reducing the accrued utility revenues balance at December 31, The Company received or has requested regula-1993. The remaining balance in the Michigan tory approval to issue up to $ 185 million of long-jurisdiction will be recovered in 1994. term debt and preferred stock. Management expects to use the proceeds to retire short-term Taxes accrued increased in 1993 reflecting the debt, refinance higher cost and maturing long-term effects of federal income tax return audit settle- debt, refund cumulative preferred stock and fund ments recorded in 1992. A significant refund construction expenditures.

resulting from the audit caused a reduction in the 1992 balance. Unless the Company meets certain earnings or coverage tests, additional long-term debt or pre-Regulatory Assets and Deferred ferred stock cannot be issued. In order to issue Tax Liabilities Increase long-term debt without refunding an equal amount of existing debt, pre-tax earnings must be equal to The Company prospectively adopted a new at least twice annual interest charges on long-term accounting standard for income taxes on January debt after giving effect to the new debt. To issue 1, 1993. The new standard required, among other additional preferred stock, after-tax gross income things, that regulated entities record deferred tax must be at least equal to one and one-half times liabilities on temporary differences previously annual interest and preferred stock dividend re-flowed-through for rate-making and book account- quirements after giving effect to the new preferred ing. Where rate-making provides for flow-through stock. The Company presently exceeds these treatment, corresponding regulatory assets were minimum coverage requirements. At December 31, recorded resulting in an increase in total assets and 1993, long-term debt and preferred stock coverage liabilities. ratios were 4.59 and 2.48, respectively.

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Recently a major credit rating agency reevaluat- Although management may have opportunities ed the credit worthiness of companies in the to improve shareholder value through increased electric utility industry based on perceived risk from competition as a result of open transmission access deregulation, increased competition, reduced load and other provisions of the Energy Policy Act of growth, escalating nuclear plant costs and environ- 1992, there is risk and uncertainty, especially for mental concerns. The agency lowered its ratings retail ratepayers and shareholders, regarding reli-outlook for approximately one-third of the com- ability of future transmission service and fair panies but not for Indiana Michigan Power which compensation for use of the Company's extensive was regarded by the agency as being relatively well high voltage transmission facilities. Management's positioned to meet future competitive challenges. goal is to ensure that, to the extent the Company's facilities are used by others, there is fair and Competition appropriate compensation.

Since 1990, the short-term wholesale energy Environmental Concerns and Cost Pressures market has been extremely competitive. With the passage of the Energy Policy Act of 1992, which Clean Alr Act provides for greater ease of transmission access and reduces certain regulatory restrictions for The Clean Air Act Amendments of 1990 independent power producers (IPPs), competition is (CAAA) require, among other things, substantial expected to increase in the long-term wholesale reductions in sulfur dioxide and nitrogen oxides market and in the construction of new generating emitted from electric generating plants, capacity. For example, IPPs are no longer required to find an industrial host to utilize the steam by- Two of the Company's generating units, Tan-product from the generation of electricity to build ners Creek Unit 4 and the Breed Plant, are affected a generating unit and avoid regulation under the by the first phase of the CAAA. Tanners Creek Public Utility Holding Company Act of 1935 (1935 Unit 4 will comply by fuel switching at minimal Act). The Energy Policy Act also exempts IPPs capital cost. Management decided early in 1994 to from requirements under the 1935 Act which, close the 325 megawatt (mw) Breed Plant as of among other things, permit IPPs to use greater March 31, 1994, due to its design and age (com-amounts of lower cost debt which may reduce mercial operation began in 1960) as well as the overall cost of capital. Thus IPPs may have a additional cost of complying with the CAAA.

competitive advantage. Although the Energy Policy Act specifically prohibits the Federal Energy Regula- The closing of the Breed Plant is not expected tory Commission from ordering retail transmission to adversely affect results of operations or financial access, the states can do so and many believe that condition except as it impacts ongoing Power Pool the next logical step will be the extension of com- credits and charges.

petition for existing industrial customers which will present both opportunities and challenges for the The ongoing earnings effe'ct of closing the Company. Breed Plant will be that the Company will receive less capacity credits for being a net supplier to the Although management believes that the Compa- Power Pool, partially offset by a reduction in ny is well positioned to compete in this evolving operation, maintenance and depreciation expenses.

competitive market because of its technical skills As of December 31, 1993 the unfavorable effect and expertise and its position as a low cost produc- on earnings is expected to be $ 10 million annually.

er, we intend to continue to examine ways to im- The Company will seek recovery of this additional prove the Company's competitive position. Efforts cost in future rate cases, to improve operations and reduce costs will contin-ue,in order to maintain and enhance our position as Phase II of the CAAA, effective in the year a low cost producer. 2000, will require further actions to comply.

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

Global Warming evidence to support them. As long as there is uncertainty about EMF, we will have difficulty Concern about global climate change, or "the finding acceptable sites for our transmission facil-greenhouse effect" has been the focus of intensive ities, which could hamper economic growth within debate within the United States and around the our service area. If the present energy delivery world. Much of the uncertainty about what effects system must be changed because of EMF con-greenhouse gas concentrations will have on the cerns, or if the courts conclude that EMF exposure global climate results from a myriad of factors that harms individuals and that utilities are liable for affect climate. Based on the terms of a 1992 damages, then results of operations and financial United Nations treaty that pledged the United condition could be adversely affected, unless the States to reduce greenhouse gas emissions, the costs can be recovered from customers.

Clinton Administration developed a voluntary plan to reduce by the year 2000 greenhouse gas emis- Hazardous Material sions to 1990 levels. The AEP System supports the plan and will work with the U.S. Department of By-products from the generation of electricity Energy (DOE) and other electric utility companies to include materials such as ash, slag, sludge, low formulate a cost effective framework for limiting level radioactive waste and spent nuclear fuel. In future greenhouse gas emissions. addition, generating plants and transmission and distribution facilities have used asbestos, The AEP System strongly supports a policy of polychlorinated biphenyls (PCBs) and other hazard-proactive environmental stewardship, whereby ous and non-hazardous materials. Substantial actions are taken that make economic and environ- costs to store and dispose of hazardous and non-mental sense on their own merits, irrespective of hazardous materials have been and will continue to the uncertain threat of global climate change. To be incurred. Significant additional costs could be reduce emissions, we support energy conservation incurred to comply with new laws and regulations programs, development of more efficient generation if enacted and to clean up disposal sites under and end-use technologies, and forest management existing legislation.

activities because they are cost effective and bring long-term benefits to our service area. Should The Superfund created by the Comprehensive significant new measures to control the burning of Environmental Response Compensation and Liability coal be enacted, they could affect the Company's Act addresses cleanup of hazardous substance competitiveness and, if not recovered from custom- disposal sites and authorizes the United States ers, adversely impact results of operations and Environmental Protection Agency (Federal EPA) to financial condition. 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.

The potential for electric and magnetic fields For two of the PRP sites, liability has been settled (EMF) from transmission and distribution facilities with little impact on results of operations. I%M to adversely affect the public health is being exten- also has been named a PRP at one Illinois site and sively researched. The AEP System continues to has received an information request for one Indiana support EMF research to help determine the extent, site under analogous state cleanup laws. Although if any, to which EMF may adversely impact public the potential liability associated with each site must health. Our concern is that new laws imposing be evaluated individually, several general state-EMF limits may be passed or new regulations ments can be made regarding such potential liabili-promulgated without sufficient scientific study and

INDIANAMICHlGANPOWER COMPANY AND SUBSIDIARIES Whether the Company disposed of hazardous its nuclear operations and staff to address these substances at a particular site is often unsubstan- concerns. Efforts are continuing to shorten refuel-tiated; the quantity of material disposed of at a site ing and maintenance outages, to reduce their cost was generally small; and the nature of the material and to minimize the cost of replacement energy generally disposed of was non-hazardous, Typical- during the outage periods. Should the nuclear units ly, the Company is one of many parties named be retired early for any reason or costs of maintain-PRPs for a site and, although liability is joint and ing, operating and decommissioning the plant and several, at least some of the other parties are disposing of its spent nuclear fuel not be recovered financially sound enterprises. Therefore, present through rates, results of operations and financial estimates do not anticipate material cleanup costs condition would be adversely affected.

for identified disposal sites. However, if for un-known reasons, significant costs are incurred for Litigation cleanup, results of operations and possibly financial condition would be adversely affected unless the The Company is involved in a number of legal costs can by recovered from insurance proceeds proceedings and claims. While we are unable to and/or customers. predict the outcome of such litigation, it is not expected that the resolution of these matters will Nuclear Operating Cost have a material adverse effect on financial condi-tion.

Operation and maintenance costs of the Comp-any's two-unit 2,110 mw Donald C. Cook Nuclear New Accounting Standards Plant are directly impacted by increasing Nuclear Regulatory Commission requirements and increas- Two new accounting standards were issued in ing maintenance requirements related to the aging 1993 that were adopted in 1994. The implementa-of the units (Unit 1 began commercial operation in tion of these new standards will not have a signifi-1975 and Unit 2 in 1978). While nuclear fuel cost cant effect on results of operations or financial has declined, the estimated cost to decommission condition.

the plant has increased to a range of $ 588 million to $ 1.1 billion. The increase in the range from Effects of inflation previous estimates is attributable to uncertainty regarding future delays in the DOE's mandatory Inflation affects the cost of replacing utility plant Spent Nuclear Fuel (SNF) disposal program. Delays and the cost of operating and maintaining such in finding a permanent repository for SNF have in- plant. The rate-making process generally limits creased costs reflecting a need to store SNF at the recovery to the historical cost of assets resulting in plant site for an extended time after the plant economic losses when inflation effects are not ceases operations. Management intends to contin- recovered from customers on a timely basis.

ue to seek recovery of increasing decommissioning However, economic gains that result from the costs over the remaining plant life. We continue to repayment of long-term debt with inflated dollars examine our operations for better ways to operate partly offset such losses.

and maintain our two nuclear units to control the growth in operation, maintenance and decommis-sioning costs. Management recently restructured

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

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Y rE D m r

~12 (in thousands)

OPERATING REVENUES ~12 ~24 ~11 L77 ~1~22'jJ+7 OPERATING EXPENSES:

Fuel 220,206 193,830 251,325 Purchased Power 108,274 180,365 122,573 Other Operation 264,543 251,897 246,935 Maintenance 142,637 137,787 119,242 Depreciation and Amortization 138,794 133,365 132,285 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 15,644 16,303 16,961 Taxes Other Than Federal Income Taxes 67,918 62,189 62,783 Federal Income Taxes ~47 7 2!~4 ~4474 Total Operating Expenses ~2~72 ~1~2 ~~7 OPERATING INCOME 209,920 195,520 227,289 NONOPERATING INCOME (LOSS) ~21 ~411 ~21 INCOME BEFORE INTEREST CHARGES 209,686 209,635 223,568 INTEREST CHARGES ~MiGZ ~MQ5.

NET INCOME 129,313 123,948 136,932 PREFERRED STOCK DIVIDEND REQUIREMENTS ~14 22 ~141 1'~

EARNINGS APPLICABLE TO COMMON STOCK ~115 088 ~108 531 ~121 51 See Notes to Consolidated Financiel Statements.

11

Consolidated Balance Sheets m r 1

~1 ~12 (in thousands)

ASSETS ELECTRIC UTILITY PLANT:

Production 02,602,527 $ 2,559,905 Transmission 839,198 829,507 Distribution 608,752 576,309 General (including nuclear fuel) 152,470 182,414 Construction Work in Progress ~11 4 Total Electric Utility Plant 4,290,957 4,266,480 Accumulated Depreciation and Amortization ~7~42

~27~12

~~4 NET ELECTRIC UTILITY PLANT ~2;~~42 OTHER PROPERTY AND INVESTMENTS ~4~24 CURRENT ASSETS:

Cash and Cash Equivalents 3,752 7,459 Accounts Receivable:

Customers 67,246 62,325 Affiliated Companies 24,507 41,139 Miscellaneous 30,087 31,536 Allowance for Uncollectible Accounts (504) (562)

Fuel - at average cost 34,476 53,210 Materials and Supplies - at average cost 57,800 54,004 Accrued Utility Revenues 34,642 78,555 Prepayments ~12 4 ~11 1 TOTAL CURRENT ASSETS ~2~44 ~QUUL22.

REGULATORY ASSETS:

Amounts Due From Customers For Future Federal Income Taxes 286,948 Other ~2~74 TOTAL REGULATORY ASSETS ~42 2 ~2LRK TOTAL 3 765 458 ~3845 798 See lvotes to Consolideted Rnenoiel Stetements.

12

IND NA MICHIGANPOWER COMPANY AND SUBSIDIARIES m r

~1 (in thousands)

CAPITALIZATIONAND LIABILITIES CAPITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares S 56,584 56,584 Paid-in Capital 734,933 726,157 Retained Earnings 17~7 171~

Total Common Shareowner's Equity '969,155 954,050 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption 87,000 197,000 Subject to Mandatory Redemption 100,000 Long-term Debt ~17~14 ~11 ~72 TOTAL CAPITALIZATION ~222~$ ~21!~71 OTHER NONCURRENT LIABILITIES ~21 7 ~27~

CURRENT LIABILITIES:

Long-term Debt Due Within One Year 42,902 Short-term Debt - Commercial Paper 50,075 44,200 Accounts Payable:

General 40,437 37,214 Affiliated Companies 17,481 12,471 Taxes Accrued 54,473 15,829 Interest Accrued 18,894 22,759 Obligations Under Capital Leases 20,585 32,745 Other 7,'~7 TOTAL CURRENT LIABILITIES ~21 1 2 ~2I~11 DEFERRED FEDERAL INCOME TAXES DEFERRED INVESTMENT TAX CREDITS ~1LQ32 ~1'MM4 DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 211 44 ~2'~4 DEFERRED CREDITS 1 242 17 7 COMMITMENTS AND CONTINGENCIES (Note 3)

TOTAL $3 765 458 3 645 79

Consolidated Statements of Cash Flows rEn D m 93 1 992 (in thousands)

OPERATING ACTIVITIES:

Net Income S 129,313 0 123,948 S 136,932 Adjustments for Noncash Items:

Depreciation and Amortization 148,270 141,453 141,813 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 15,644 16,303 16,961 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) 33,827 (47,200)

Deferred Federal Income Taxes (49,905) 29,897 (21,877)

Deferred Investment Tax Credits (8,543) (9,673) (9,188)

Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net) 13,102 (7,432) (4,389)

Fuel, Materials and Supplies 14,938 1,018 (14,520)

Accrued Utility Revenues 43,913 (41,068) 3,816 Accounts Payable 8,233 (15,088) (15,222)

Taxes Accrued 38,644 4,514 9,937 Other (net) ~17~4 ~1I~44 ~444 Net Cash Flows From Operating Activities ~7~72 ~122M2 ~24 ~7 INVESTING ACTIVITIES:

Construction Expenditures (108,867) (125,908) (122,597)

Proceeds from Sales of Property and Other ~i2Li ~24 Net Cash Flows Used For Investing Activities ~1'~42) J1%$ 2$ ~LAD FINANCING ACTIVITIES:

Capital Contributions from Parent Company 10,000 Issuance of Cumulative Preferred Stock 98,776 Issuance of Long-term Debt 243,426 271,722 78,634 Retirement of Cumulative Preferred Stock (112,300)

Retirement of Long-term Debt (392,093) (203,185) (92,623)

Change in Short-term Debt (net) 5,875 (6,750) 12,055 Dividends Paid on Common Stock (108,696) (106,465) (102,680)

Dividends Paid on Cumulative Preferred Stock ~1~7~ ~141 7 ~141 7 Net Cash Flows Used For Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents

~27 )~7 (3,707)

~I~) (4,876)

~2~391 9,327 Cash and Cash Equivalents January 1 Cash and Cash Equivalents December 31

~74 12~ ~hQQR 3 752 7 459 See Notes to Consolidated RnanoIol Statements.

14

.

~ t INDIANAMICHIGANPOWER COMPANY AND SU8SIDIARIES Consolidated Statements of Retained Earnings Y rEn D m 1

~12 (in thousands)

Retained Earnings January 0171,309 $ 169,243 $ 150,408 Net Income 1

~12 1~1 ~12 l~4 ~i~2

~01~22 ~2I~11 ~27~4 Deductions:

Cash Dividends Declared:

Common Stock 108,696 106,465 102,680 Cumulative Preferred Stock:

4-1/8% Series 495 495 495 4.56% Series 273 273 273 4.12% Series 165 165 165 5.90% Series 374 6-1/4% Series 161 6-7/8% Series 1,799 7.08% Series 2,124 2,124 2,124 7.76% Series 2,716 2,716 2,716 8,68% Series 2,517 2,604 2,604

$ 2.15

$ 2.25 Series Series Total Cash Dividends Declared 3,001 122,921

~l~ ~)~

3,440 121,882 3,440 118,097 Other Total Deductions 122 4 ~121 2 11~!L7 Retained Earnings December 31 ~177 638 171 30 ~I69 24 See Notes to Consolidoted Rnancial Statements.

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES: the recognition of revenues and expenses in differ-ent time periods than enterprises that are not rate Organization regulated. In accordance with Statement of Finan-cial Accounting Standards (SFAS) No. 71, Ac-Indiana Michigan Power Company (the Company countin g for the Effects of Certain Types of Regula-or I@M) is a wholly-owned subsidiary of American tion (SFAS 71), regulatory assets and liabilities are Electric Power Company, Inc. (AEP Co., Inc.), a recorded to defer expenses or revenues reflecting public utility holding company. The Company is such rate-making differences.

engaged in the generation, purchase, transmission and distribution of electric power in northern and UtilityPlant eastern Indiana and a portion of southwestern Michigan. As a member of the American Electric Electric utility plant is stated at original cost and Power (AEP) System Power Pool (Power Pool) and is generally subject to first mortgage liens. Addi-a signatory company to the AEP Transmission tions, major replacements and betterments are Equalization Agreement, its facilities are operated added to the plant accounts. Retirements from the in conjunction with the facilities of certain other plant accounts and associated removal costs, net AEP Co., Inc. owned utilities as an integrated utility of salvage, are deducted from accumulated depreci-system. ation.

The Company has two wholly-owned subsidiar- The costs of labor, materials and overheads ies, Blackhawk Coal Company and Price River Coal incurred to operate and maintain utility plant are Company, that were formerly engaged in coal- included in operating expenses.

mining operations. Blackhawk Coal Company cur-rently leases and subleases portions of its Utah coal Allowance for Funds Used During Construction rights, land and related mining equipment to unaffil- /AFUDCJ iated companies. Price River Coal Company, which owns no land or mineral rights, is inactive. AFUDC is a noncash income item that is recov-ered over the service life of utility plant through Regulation depreciation and represents the estimated cost of borrowed and equity funds used to finance con-As a member of the AEP System, IRM is subject struction projects. The average rates used to to regulation by the Securities and Exchange Com- accrue AFUDC were 8.75% in 1993 and 9.25% in mission (SEC) under the Public UtilityHolding Com- 1992 and 1991 and the amounts of AFUDC ac-pany Act of 1935 (1935 Act). Retail rates are crued were $ 1.7 million, $ 3.8 million and S2.1 regulated by the Indiana UtilityRegulatory Commis- million in 1993, 1992 and 1991, respectively.

sion (IURC) and the Michigan Public Service Com-mission (MPSC). The Federal Energy Regulatory Depreciation and Amortization Commission (FERC) regulates wholesale rates.

Depreciation is provided on a straight-line basis Principles of Consolidation over the estimated useful lives of utility plant and is calculated largely through the use of composite The consolidated financial statements include rates by functional class (i.e., production, transmis-ISM and its wholly-owned subsidiaries. Significant sion, distribution, etc.). Amounts to be used for intercompany items were eliminated in consolida- demolition of non-nuclear plant are presently tion. recovered through depreciation charges included in rates. The accounting and rate-making treatment Basis of Accounting afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3.

As a rate-regulated entity, I@M's financial state-ments reflect the actions of regulators that result in 16

.

~ t INDIANAMICHIGANPOVYER COMPANY AND SUBSIDIARIES Rockport Plant Income Texes Rockport Plant consists of two 1,300 megawatt Effective January 1, 1993, the Company adopted (mw) coal-fired units. ILM and AEP Generating the liability method of accounting for income taxes Company (AEGCo), an affiliate, each owns 50% of as prescribed by SFAS 109, Accounting for Income one unit (Rockport 1) and each leases a 50% Texes. Under this standard deferred federal income interest in the other unit (Rockport 2) from unaffili- taxes are provided for all temporary differences ated lessors under an operating lease. The gain on between the book cost and tax basis of assets and the sale and leaseback of Rockport 2 was deferred liabilities which will result in a future tax conse-and is being amortized, with related taxes, over the quence. In prior years deferred federal income initial lease term which expires in 2022. taxes were provided for timing differences between book and taxable income except where flow-Rate phase-in plans provide for the recovery and through accounting for certain differences was straight-line amortization through 1997 of prior- reflected in rates. Flow-through accounting is a year deferrals of Rockport 1 costs. Deferred method whereby federal income tax expense for a amounts under the phase-in plans were $ 59 million particular item is the same for accounting and rate-and $ 75 million at December 31, 1993 and 1992, making as in the federal income tax return. As a respectively. result of the adoption of SFAS 109 significant additional deferred tax liabilities were recorded for Cash and Cash Equivalents items afforded flow-through treatment in rates. In accordance with SFAS 71 significant corresponding Cash and cash equivalents include temporary regulatory assets were also recorded to reflect the cash investments with original maturities of three future recovery of additional taxes due when the months or less. temporary differences reverse. As a result of this change in accounting effective January 1, 1993, Operetin g Revenues deferred federal income tax liabilities increased by

$ 259.6 million and regulatory assets by $ 254.3 Revenues include an accrual for electricity con- million, and net income was reduced by $ 5.3 sumed but unbilled at month-end as well as billed million.

revenues, Investment tax credits utilized in prior income tax returns were deferred and are years'ederal Fuel Costs being amortized over the life of the related plant Fuel costs are matched with revenues in accor- investment in accordance with rate-making treat-dance with rate commission orders. Revenues are ment.

accrued related to unrecovered fuel in both retail jurisdictions and for replacement power costs in the Debt and Preferred Stock Michigan jurisdiction until approved for billing.

Wholesale jurisdictional fuel cost changes are Gains and losses on reacquired debt are deferred expensed and billed as incurred. and amortized over the term of the reacquired debt.

If the debt is refinanced the reacquisition costs are Levelization of Nuclear Refueling Outage Costs deferred and amortized over the term of the re-placement debt.

Increme'ntal operation and maintenance costs associated with refueling outages at the Donald C. Debt discount or premium and debt issuance Cook Nuclear Plant (Cook Plant) are deferred with expenses are amortized over the term of the related the approval of regulators for amortization over the debt, with the amortization included in interest period (generally eighteen months) beginning with charges.

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.

17

Redemption premiums paid to reacquire preferred operation from the Company in 1986 and affiliated stock are deferred and amortized in accordance coal transportation charges. In December 1993 the with rate-making treatment. The excess of par wholesale customer appealed the FERC order to the value over costs of preferred stock reacquired to U.S. Court of Appeals.

meet sinking fund requirements is credited to paid-in capital.

3. COMMITMENTSAND CONTINGENCIES:

Other Property and /nvestments Construction and Other Commitments Other property and investments are generally stated at cost. Substantial construction commitments have been made although no new generating capacity is Reclassifications expected to be constructed until the next century.

The aggregate construction program expenditures Certain prior-period amounts were reclassified to for 1994-1996 are estimated to be 0410 million conform with current-period presentation. and include the capital cost of compliance with the Clean Air Act Amendments of 1990 (CAAA).

2. RATE MATTERS: Long-term fuel supply contracts contain clauses for periodic adjustments. The retail jurisdictions Rate Activity have fuel clause mechanisms that provide with the regulators'eview and approval for deferred recov-In November 1993 the IURC granted a $ 34.7 ery of changes in the cost of fuel. The contracts million annual rate increase in response to the are for various terms, the longest of which extend Company's request for a $ 44.8 million increase to 2014, and contain various clauses that would filed in April 1992. The new rates include, among release the Company from its obligation under other things, recovery of the ongoing amounts certain force majeure conditions.

being accrued for postretirement benefits other than pensions (OPEB), an increase in the provision Unit Power Agreements for nuclear plant decommissioning costs and the amortization of deferred incremental nuclear plant The Company is committed under unit power refueling outage costs. agreements to purchase 70% of AEGCo's Rockport Plant capacity unless it is sold to unaffiliated In October 1993 the MPSC approved a settle- utilities. AEGCo has one long-term contract with ment agreement that provides for a three-step an unaffiliated utility that expires in 1999 for 455 increase in recovery of nuclear decommissioning mw of Rockport Plant capacity.

costs for the Cook Plant. The first step increase of

$ 1.2 million annually was effective in November The Company sells under contract up to 250 mw 1993. The second and third steps provide for of Rockport Plant capacity to Carolina Power and recoveries to be increased by $ 1 million annually in Light Company, an unaffiliated utility. The contract May 1994 and an additional $ 1 million annually in expires in 2009.

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

An appeal to the Indiana Court of Appeals by a Unaffjliated Coal and Affiliated Transportation Cost local distribution utility of a 1992 DeKalb County Recovery Circuit Court of Indiana decision is pending, The circuit court dismissed the case filed under a In October 1993 the FERC denied a request by a provision of Indiana law that allows the local distri-wholesale customer seeking rehearing of a February bution utility to seek damages equal to the gross 1993 order. The February 1993 order reversed a revenues received by the Company for rendering 1990 administrative law judge's initial decision and service in the designated service territory of the dismissed the wholesale customer's complaint local distribution utility. The Company had re-concerning the reasonableness of coal costs from ceived approximately $ 29 million in gross revenues an unaffiliated supplier who leased a Utah mining from a major industrial customer in the local distri-18

.

~ INDIANAMICHIGANPOWER COMPANy'ND SUBSIDIARIES bution utility's service territory. The case resulted could be incurred in the future to meet the require-from a Supreme Court of Indiana decision which ments of new laws and regulations, if enacted, and overruled an appeals court and voided an IURC to clean up disposal sites under existing legislation.

order which assigned the major industrial customer to the Company. The Superfund created by the Comprehensive Environmental Response Compensation and Liability The Company is involved in other legal proceed- Act addresses cleanup of hazardous substance ings and claims. While management is unable to disposal sites and authorizes the United States predict the outcome of litigation, it is not expected Environmental Protection Agency (Federal EPA) to that the resolution of these other matters will have administer the cleanup programs. The Company a material adverse effect on financial condition. has been named by the Federal EPA as a "potential-ly responsible party" (PRP) for seven sites and has Clean AI'r received information requests for three other sites.

For two of the PRP sites, liability has been settled The CAAA require significant reductions in sulfur with little impact on results of operations. I&M dioxide and nitrogen oxides emitted from various also has been named a PRP at one Illinois site and AEP System generating plants. The law estab- has received an information request for one Indiana lished a deadline of 1995 for the first phase of site under analogous state cleanup laws. Although reductions in sulfur dioxide emissions (Phase I) and the potential liabilityassociated with each site must the year 2000 for the second phase (Phase II) as be evaluated individually, several general state-well as a permanent nationwide cap on sulfur ments can be made regarding such potential liabili-dioxide emissions after 1999.

The AEP Systemwide compliance plan calls for Whether the Company disposed of hazardous fuel switching to medium-sulfur coal at I&M's substances at a particular site is often unsubstanti-Tanners Creek Unit 4 with minimal capital cost. ated; the quantity of material disposed of at a site The Breed unit which is a Phase I affected unit is was generally small; and the nature of the material scheduled to close on March 31, 1994. The generally disposed of was non-hazardous. Typical-Company's other generating units are not affected ly, the Company is one of many parties named in Phase I. PRPs for a site and, although liability is joint and several, at least some of the other parties are The Company will incur additional costs to generally financially sound enterprises. Therefore, comply with Phase II requirements at its generating present estimates do not anticipate material clean-plants. In addition, a portion of the costs of com- up costs for identified disposal sites. However, if pliance for the AEP System may be incurred for unknown reasons, significant costs are incurred through the Power Pool (which is described in Note for cleanup, results of operations and possibly 5). If I&M is unable to recover compliance costs financial condition would be adversely affected from its customers, results of operations and unless the costs can by recovered from insurance financial condition would b'e adversely impacted. proceeds and/or customers, Other Fnvironmental Matters Nuclear Plant The Company and its subsidiaries are regulated l&M owns and operates the two-unit 2,110 mw by federal, state and local authorities with respect Cook Plant under licenses granted by regulatory to air and water quality and other environmental authorities, The operation of a nuclear facility matters. involves special risks, potential liabilities, and specific regulatory and safety requirements.

The generation of electricity produces non-haz- Should a nuclear incident occur at any facility in ardous and hazardous by-products. Asbestos, the United States liability could be substantial.

polychlorinated biphenyls (PCBs) and other hazard- Should nuclear losses or liabilities be underinsured ous materials have been used in the generating or exceed accumulated funds, or should rate plants and transmission/distribution facilities. recovery be denied, results of operations and Substantial costs to store and dispose of hazardous financial condition would be negatively affected, and non-hazardous materials have been incurred Specific information about risk management and and will be incurred. Significant additional costs potential liabilities is discussed below.

19

Nuclear Insurance operate the two nuclear units expire in 2014 and 2017. After expiration of the licenses the plant is Public liability is limited by law to $ 9.4 billion expected to be decommissioned through disman-should an incident occur at any licensed reactor in tling. Estimated decommissioning costs range from the United States. Commercially available insur- $ 588 million to $ 1.1 billion in 1991 dollars. The ance provides $ 200 million of this coverage. In the wide range is caused by variables in the estimated event of a nuclear incident at any nuclear plant in length of time spent nuclear fuel must be stored at the United States the remainder of the liability the plant subsequent to ceasing operations which would be provided by a deferred premium assess- depends on future developments in the federal ment of $ 79.3 million on each licensed reactor government's spent nuclear fuel disposal program.

payable in annual installments of $ 10 million. As Decommissioning costs are being recovered based a result, IRM could be assessed $ 158.6 million per on at least the lower end of the range in the cur-nuclear incident payable in annual installments of rent and prior studies. I@M records decommission-

$ 20 million. The number of incidents for which ing costs in other operation expense and records a payments could be required is not limited. noncurrent decommissioning liability equal to the rate recovery which was $ 13 million in 1993, $ 12 Nuclear insurance pools and other insurance million in 1992 and $ 11 million in 1991. Decom-policies provide $ 2.75 billion of property damage, missioning amounts recovered from customers are decommissioning and decontamination coverage for deposited in external trusts. Trust fund earnings Cook Plant. Additional insurance provides cover- increase the fund assets and the recorded liability.

age for extra costs resulting from a prolonged Trust fund earnings decrease the amount to be accidental Cook Plant outage. Some of the policies recovered from ratepayers. At December 31, have deferred premium provisions which could be 1993, the decommissioning trust fund balance and triggered by losses in excess of the insurer's the accumulated provision for decommissioning resources. The losses could result from claims at were $ 170 million.

the Cook Plant or certain other nuclear units. The Company could be assessed up to $ 24 million In recent rate increases, which are discussed in under these policies. Note 2, the Company received additional annual amounts for the decommissioning of the Cook Plant Spent Nuclear Fue/ Disposal of $ 10 million in its Indiana jurisdiction and 03.2 million phased-in in its Michigan jurisdiction.

Federal law provides for government responsibili-ty for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel 4. COMMON SHAREOWNER'S EQUITY:

disposal. The fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collect- Mortgage indentures, debentures, charter provi-ed from customers and remitted to the U.S. Trea- sions and orders of regulatory authorities place sury. Fees and related interest of $ 148 million for various restrictions on the use of retained earnings fuel consumed prior to April 7, 1983 have been for the payment of cash dividends on common recorded as long-term debt and a regulatory asset. stock, At December 31, 1993, $ 5.9 million of The regulatory asset is being amortized as rate retained earnings were restricted. Regulatory recovery occurs. I%M has not paid the government approval is required to pay dividends out of paid-in the pre-April 1983 fees due to various factors capital.

including continued delays and uncertainties related to the federal disposal program. At December 31, In 1993, I%M's parent made a cash capital 1993, funds collected from customers to dispose contribution of $ 10 million. Also in 1993 S1.2 of nuclear fuel and related earnings totalling $ 133 million, representing the issuance costs for three million were held in external funds included in the series of cumulative preferred stock, was charged financial statements as other property and invest- to paid-in capital, There were no other transactions ments. affecting the common stock or paid-in capital accounts in 1993, 1992 or 1991.

Decommissioning Decommissioning costs are accrued over the service life of the Cook Plant. The licenses to 20

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

5. RELATED PARTY TRANSACTIONS: recorded in other operation expense for transmis-sion services in 1993, 1992 and 1991, respective-Benefits and costs of the System's generating ly.

plants are shared by members of the Power Pool.

Under the terms of the System Interconnection Revenues from providing barging services were Agreement, capacity charges and credits are recorded in nonoperating income as follows:

designed to allocate the cost of the System's capacity among the Power Pool members based on Year Ended Oecemb r their relative peak demands and generating re- ~993 ~9 ~9 (in thousands) serves. Power Pool members are compensated for the out-of-pocket costs of energy delivered to the Affiliated Companies $ 25,372 $ 24,753 $ 23,863 Power Pool and charged for energy received from Unafflllated Cempanlea 1 717 3 964 4 641 Total ~27 089 ~28 717 ~28 604 the Power Pool.

American Electric Power Service Corporation Operating revenues include $ 204.6 million in (AEPSC) provides certain managerial and profes-1993, $ 154.1 million in 1992 and $ 204.8 million sional services to AEP System companies. The in 1991 for supplying energy and capacity to the costs of the services are determined by AEPSC on Power Pool. Purchased power expense includes a direct-charge basis to the extent practicable and charges of $ 20.9 million in 1993, $ 82.6 million in on reasonable bases of proration for indirect costs.

1992 and $ 24.6 million in 1991 for energy re- The charges for services are made at cost and ceived from the Power Pool. include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co Power Pool members share in wholesale sales to Inc. Billings from AEPSC are capitalized or unaffiliated utilities made by the Power Pool. The expensed depending on the nature of the services Company's share was included in operating reve- rendered. AEPSC and its billings are subject to the nues in the amount of $ 57 million in 1993, $ 45.8 regulation of the SEC under the 1935 Act.

million in 1992 and $ 65.5 million in 1991.

In addition, the Power Pool purchases power 6. BENEFIT PLANS:

from unaffiliated companies for immediate resale to other unaffiliated utilities. The Company's share of The Company and its subsidiaries participate in these purchases was included in purchased power the AEP System pension plan, a trusteed, noncon-expense and totaled $ 5.1 million in 1993, $ 6.5 tributory defined benefit plan covering all employ-million in 1992 and $ 13.7 million in 1991. Reve- ees meeting eligibility requirements, Benefits are nues from these transactions are included in the based on service years and compensation levels.

above Power Pool wholesale sales. Effective January 1, 1992 employees may retire without reduction of benefits at age 62 and with The cost of power purchased from AEGCo, an reduced benefits as early as age 55. Pension costs affiliated company that is not a member of the are allocated by first charging each System compa-Power Pool, was included in purchased power ny with its service cost and then allocating the expense in the amounts of $ 78.9 million, $ 88 remaining pension cost in proportion to its share of million and $ 83 million in 1993, 1992 and 1991, the projected benefit obligation. The funding policy respectively. is to make annual trust fund contributions equal to the net periodic pension cost up to the maximum The Company operates the Rockport Plant and amount deductible for federal income taxes, but bills AEGCo for its share of operating costs. not less than the minimum contribution required by law.

AEP System companies participate in a transmis-sion equalization agreement. This agreement Net pension costs for the years ended December combines certain AEP System companies'nvest- 31, 1993, 1992 and 1991 were $ 4.7 million, $ 5.6 ments in transmission facilities and shares the million and $ 2.3 million, respectively.

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 21

2

~

~ )

An employee savings plan is offered which To reduce the impact of adopting SFAS 106, allows participants to contribute up to 16% of their management took several measures. First, a salaries into three investment alternatives, including Voluntary Employees Beneficiary Association AEP Co., Inc. common stock. The Company (VEBA) trust fund for OPEB benefits was estab-contributes an amount equal to one-half of the first lished. A 84.3 million advance contribution was 6% of the employees'ontribution. The made to the trust fund in 1990, the maximum Company's contribution is invested in AEP Co., Inc. amount deductible for federal income tax purposes.

common stock and totaled 83.5 million in 1993, In 1993, a $ 700,000 contribution was made to the 83.3 million in 1992 and $ 3.1 million in 1991. VESA trust fund from amounts recovered from ratepayers. In addition, to help fund and reduce The AEP System provides certain other benefits the future costs of OPEB benefits, a COLI program for retired employees under an AEP System other was implemented, except where restricted by state postretirement benefit plan. Substantially all Iaw. The insurance policies have a substantial cash employees are eligible for health care and life surrender value which is recorded, net of equally insurance benefits if they have at least 10 service substantial policy loans, as other property and years and, effective January 1, 1992, are age 55 investments. The policies generated cash of at retirement. Prior to 1993, net costs of these 8600,000 in 1993, $ 1,700,000 in 1992 and benefits were recognized as an expense when paid $ 700,000 in 1991 inclusive of related tax benefits and totaled 82.7 million and 82.6 million in 1992 which was contributed to the VEBA trust fund. In and 1991, respectively. 1997 the premium will be fully paid and the cash generated by the policies should increase signifi-SFAS 106, Employers'ccounting for cantly.

Postretirement Benefits Other Than Pensions, was adopted in January 1993. SFAS 106 requires the accrual of the present value liability for the cost of 7. SUPPLEMENTARY INFORMATION:

postretirement benefits other than pensions (OPEB) during the employee's service years. Prior service Year Ended December 31 costs are being recognized as a transition obligation ~993 ~99 ~9 over 20 years in accordance with SFAS 106. (in thousands)

Taxes other than federal OPEB costs are based on actuarially-determined income taxes include:

stand alone costs for each System company. The Real and Personal funding policy is to contribute incremental amounts Property $ 35 683 $ 359818 $ 339265 State Gross Receipts, recovered through rates and cash generated by the Excise, Franchise corporate owned life insurance (COLI) program. and Hiscellaneous The annual accrued costs for 1993 required by State and Local 15,008 15,179 15,902 SFAS 106 for employees and retirees, which Payroll 9,001 8,911 8,075 includes the recognition of one-twentieth of the State Income ~82 6 ~28 ~554 Total ~67 978 ~62 189 ~62 783 prior service transition obligation, was $ 12.4 million.

Cash was paid for:

Interest (net of The Company received approval from the IURC to capitalized amounts) $ 82,509 $ 84,691 $ 84,581 recover the increased OPEB costs. In the Michigan Income Taxes 68,303 15,285 73,694 and wholesale jurisdictions, the Company received authority to defer the increased OPEB costs which Noncash acquisitions under capital are not being currently recovered in rates. Future leases were 15,467 47,905 25,624 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.

22

INDIANAMICHIGANPOWER COhrPANY AND SUBSIDIARIES

8. FEDERAL INCOME TAXES:

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

Year Ended December 31 1993 ~199 ~99 (in thousands)

Charged (Credited) to Operating Expenses (net):

Current $ 93,974 $ 9,122 $ 73,702 Deferred (50,959) 25,405 (18,793)

Deferred Investment Tax Credits ~0308) ~9020) ~0435)

Total 34 707 25 499 46 474 Charged (Credited) to Nonoperating Income (net):

Current 6,026 1,569 3,348 Deferred 1,054 4,492 (3,084)

Deferred Investment Tax Credits ~235) ~645) ~753)

Total 6 045 5 416 ~409)

Total Federal Income Taxes as Reported ~47 55 ~30 915 ~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.

Year Ended December 31 1993 ~199 ~99 (in thousands)

Net Income $ 129,313 $ 123,948 $ 136,932 Federal Income Taxes 41 552 3D 915 45 985 Pre-tax Book Income ~770 065 ~754 063 ~702 917 Federal Income Tax on Pre-tax Book Income at Statutory Rate (35K in 1993 and 34K in 1992 and 1991) $ 59,803 $ 52,653 $ 62,192 Increase (Decrease) in Federal Income Tax Resulting From the Following Items:

Removal Costs (2,632) (3,042) (2,259)

Adoption of SFAS 109 5,271 Investment Tax Credits (net) (8,543) (9,011) (9,087)

Corporate Owned Life Insurance (4,697) (4,402) (3,044)

Other ~7650) ~5203 ) ~)0) 7)

Total Federal Income Taxes as Reported ~41 552 ~30 915 ~45 905 Effective Federal Income Tax Rate 24.3X 20.0X 25.IX 23

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

Year nded December 31 1993 ~199 ~99 (in thousands)

Current:

Federal Income Taxes Investment Tax Credits Total Current Federal Income Taxes

$ 100,000 100 000

$ 10,029

~66 10 691

~0

$ 76,949 77 050 Deferred:

Depreciation (12,167) (8,356) (6,969)

Unrecovered and Levelized Fuel (13,795) 11,729 (670)

Nuclear Fuel (3,271) 5,410 (6,484)

Deferred Return - Rockport Plant Unit 1 (2,644) (2,772) (2,864)

Deferred Net Gain - Rockport Plant Unit 2 3,922 4,230 3,098 Levelized Nuclear Refueling Costs (11,488) 16,048 Accrued Interest Income (3,854) 3,854 Adoption of SFAS 109 5,271 Other ~)) 079) ~246) ~7900)

Total Deferred Federal Income Taxes ~49 905) 29 097 ~2) 077)

Total Deferred Investment Tax Credits ~0543) ~9673) ~9108)

Total Federal Income Taxes as Reported ~4) 552 ~30 915 ~45 965 The Company and its subsidiaries join in the filing The net deferred tax liability of $ 553.9 million at of a consolidated federal income tax return with December 31, 1993 is composed of deferred tax their affiliates in the AEP System. The allocation of assets of $ 233.4 million and deferred tax liabilities the AEP System's current consolidated federal of $ 787.3 million. The significant temporary income tax to the System companies is in accor- differences giving rise to the net deferred tax dance with SEC rules under the 1935 Act. These liability are:

rules permit the allocation of the benefit of current tax losses and investment tax credits utilized to the Deferred Tax Asset System companies giving rise to them in determin- (Liability) ing their current tax expense. The tax loss of the (in thousands)

System parent company, AEP Co48 Inc48 is allocated Property Related Temporary Differences $ (494,966) to its subsidiaries with taxable income. With the Amounts Oue From Customers exception of the loss of the parent company, the For Future Federal Income Taxes (100,432)

Deferred Net Gain-method of allocation approximates a separate Rockport Plant Unit 2 62,761 return result for each company in the consolidated All Other (net) ~21 203) group. Total Net Deferred Tax Liability ~553 920)

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 AND SUBSIDIARIES

9. LEASES: Properties under operating leases and related obligations are not included in the Consolidated Leases of property, plant and equipment are for Balance Sheets.

periods up to 35 years and require payments of related property taxes, maintenance and operating Future minimum lease rentals consisted of the costs. The majority of the leases have purchase or following at December 31, 1993:

renewal options and will be renewed or replaced by other leases. Hon-Cancelable Capital Operating Lease rentals are generally charged to operating ~eases ~eases expense in accordance with rate-making treatment. (in thousands)

The components of rentals are as follows:

1994 $ 9,380 $ 98,667 Year Ended December 31 1995 8,574 98,203 1996 7,601 97,885 1997 6,889 96,029 (in thousands) 1998 6,257 91,118 Operating Leases $ 103,884 $ 109,466 $ 101,013 Later Years 30 303 ~20 70 Amortization of Capital Leases 46,063 24,124 54,528 Total Future Hinimum Lease Payments 77,084(al ~2493 603 Interest on Capital Leases 8 873 7 473 9 907 Total Rental Less Estimated Payments ~750 020 ~747 063 ~765 440 Interest Elnnent ~23 99 Estimated Present Properties under capital leases and related obli- Value of Future gations recorded on the Consolidated Balance Minimum Lease Sheets are as follows: Payments 53,092 Oecember 31 Unamortized Nuclear 1993 1992 Fuel 45 661 (in thousands) Total ~90753 Electric Utility Plant: (a) Hinimum lease rentals do not include nuclear fuel Production $ 8,033 $ 11,407 rentals. The rental payments are based on the heat Oistribut,ion 14,717 14,702 produced plus carrying charges on the unamortized General: nuclear fuel balance.

Nuclear Fuel (net of amortization) 45,661 84,208 Other 40410 46 494 Total Electric Utility Plant 116,829 156,811 Accumulated Amortization 27 359 30 630 Het Electric Utility Plant 89 470 6 81 Other Property 11,269 2,327 Accumulated Amortization 1 906 1 819 Het Other Property ~903 500 Het Properties under Capital Lease 98 753 126 689 Obligations under Capital Leases $ 98,753 $ 126,689 Less Portion Oue Mithin One Year 20 505 32 745 Noncurrent Liability ~70 160 ~93 944 25

10. CUMULATIVEPREFERRED STOCK:

At December 31, 1993, authorized shares of cumulative preferred stock were as follows:

Par Value Shares Authorized

$ 100 2,250,000 25 11,200,000 The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is par value. Unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. The Company issued 350,000 shares of 6.30% Cumulative Preferred Stock Subject to Mandatory Redemption, par value $ 100, on February 8, 1994 and redeemed 350,000 shares of 7.76% Cumulative Preferred Stock Not Subject to Mandatory Redemption, par value $ 100, on February 14, 1994.

A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:

Call Pr ice Shares Amount December 31, Par Number of Shares Redeemed Outstanding December 31 Series 1993 Value Year Ended December 31 December 31 1993 1993 ~199 1991 (in thousands) 4-1/8X $ 106.125 $ 100 120,000 $ 12,000 $ 12,000 4.56K 102 100 60,000 6,000 6,000 4.12K 102.728 100 40,000 4,000 4,000 7.08K 101.85 100 300,000 30,000 30,000 7.76K 102.28 100 350,000 35,000 35,000, 8.68K 300,000 30,000

$ 2.15 1,600,000 40,000

$ 2.25 1,600,000 40 000

~87 000 ~197 000 B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Shares Amount Par Outstanding December 31 Series(a) Value December 31 1993 1993 1992 (in thousands) 5.90X (b) $ 100 400,000 $ 40,000 6-1/4X(c) 100 300,000 30,000 6-7/8X(d) 100 300,000 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 will require the redemption of 20,000 shares each year and the redemption of the remaining shares outstanding on January 1, 2009, in each case at 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: Certain indentures relating to the first mortgage bonds contain improvement, maintenance and re-Long-term debt by major category was out- placement provisions requiring the deposit of cash standing as follows: or bonds with the trustee, or in lieu thereof, certifi-cation of unfunded property additions.

Decenber 31 1993 ~199 Installment purchase contracts have been entered (in thousands) into in connection with the issuance of pollution First Mortgage Bonds $ 571,468 $ 713,916 control revenue bonds by governmental authorities Installment Purchase as follows:

Contracts 307,823 308,333 Other Long. term Debt (a) 147,810 143,321 December 31 Notes Payable to Banks 40,000 40,000 1993 ~99 Sinking Fund Debentures 6 053 6 053 {in thousands) 1,073,154 1,211,623 Loss Portion Due Within ~Rate Due Ono Year 42 90 City of Lawrenceburg, Indians:

7 200B - May 1 $ 40,000 Total ~)073 154 ~))60 721 B-7/8 2006 - May 1 12,000 7 2015- Apnl 1 25,000 25,000 (a) Nuclear Fuel Disposal Costs including interest accrued. 5.9 2019 - November 1 52,000 See Note 3. City of Rockport, Indiana:

9-1/4 2014 - August 1 50,000 50,000 First mortgage bonds outstanding were as fol- B-3/4(a) 2014 - August 1 50,000 50,000 lows: (b) 2014- August 1 50,000 50,000 December 31 7.6 201B - March 1 40,000 40,000 1993 1992 City of Sullivan, Indiana:

{in thousands) 7-3/8 2004 - May 1 7,000 o

6-7/8 2006 - May 1 25,000 Rate Due 7-1/2 2009 - May 1 13,000 4-3/8 1993. August 1 $ $ 42,902 5.95 2009 - May 1 45,000 7-7/8 1997 - February 1 50,000 unamortized Discount ~4177) ~3667) 9-1/8 1997 - July 1 75,000 7 1998 - May 1 35,000 35,000 Total ~307 023 ~308333 7.30 1999 - December 15 35,000 35,000 8-7/8 2000- April 1 50,000 (a) The adjustable interest rate changed on August 1, 1990 7.60 2002 - November 1 50,000 50,000 and will change every five years thereafter.

7.70 2002 - December 15 40,000 40,000 (b) The variable interest rate is determined weekly. The 6.80 2003- July 1 20,000 average weighted intorest was 3.0% in 1993 and 3.7% for 1992.

6.55 2003 October 1

~

20,000 6.10 2003 November 1

~

30,000 Under the terms of certain installment purchase 8-3/8 2003 - December 1 40,000 9-1/2 2008 - March 1 34,034 contracts, the Company is required to pay amounts 8-3/4 2017 - February 1 100,000 100,000 sufficient to enable the cities to pay interest on and 9.50 2021 - May 1 10,000 10,000 the principal (at stated maturities and upon 9.50 202'I - May 1 10,000 10,000 mandatory redemption) of related pollution control 9.50 2021 - May 1 20,000 20,000 revenue bonds issued to finance the construction 8.75 2022- May 1 50,000 50,000 of pollution control facilities at certain generating 8.50 2022 - December 15 75,000 75,000 plants. On certain series the principal is payable at 7.80 2023 - July 1 20,000 stated maturities or on the demand of the bond-7.35 2023 - October 1 20,000 holders at periodic interest adjustment dates.

7.20 2024- February 1 40,000 Accordingly, the installment purchase contracts unamor tized Discount (net) ~353 ) ~30 0) have been classified for repayment purposes based 571,468 713,916 Less Portion Due Within One Year 42 902 on their next interest rate adjustment date. Certain series are supported by bank letters of credit which Total 571 468 ~67) 014 expire in 1995.

27

A $ 40 million unsecured promissory note payable December 31, 1993 and 1992 fair values for to a bank is due November 19, 1995 at an annual external trust funds were $ 321 million and $ 270 interest rate of 9.07%. million and carrying values were $ 303 million and

$ 262 million, respectively. Fair values for long-The sinking fund debentures are due May 1, term debt were $ 1.1 billion and $ 1.2 billion at 1998 at an interest rate of 7-1/4%. Prior to December 31, 1993 and 1992, respectively. Fair December 31, 1993, sufficient principal amounts of value at December 31, 1993 for preferred stocks debentures had been reacquired in anticipation of subject to mandatory redemption, which were all future sinking fund requirements. Additional issued in 1993, was $ 99 million. Fair values are debentures of up to $ 300,000 may be called based on quoted market prices for the same or annually. similar issues and the current dividend or interest rates offered for instruments of the same remaining At December 31, 1993, annual long-term debt maturities. External trust funds are used to accu-payments, excluding premium or discount, are as mulate funds collected from customers for future follows: nuclear liabilities and are reported on the balance Princi al Amount sheet as other property and investments. The (in thousands) carrying amount of the pre-April 1983 spent nucle-1994 $

ar fuel disposal liability approximates the 1995 140,000 Company's best estimate of its fair value.

1996 1997 1998 41,053 Later Years 899 810 13. UNAUDITED QUARTERLY FINANCIALINFOR-Total 1 080 863 IVIATION:

Short-term debt borrowings are limited by provi- quarterly Periods Operating Operating Net sions of the 1935 Act to $ 200 million and further Ended Revenues Income Income limited by charter provisions to $ 127 million. Lines (in thousands) of credit are shared with AEP System companies 1993 Harch 31 $ 302,968 $ 53,269 $ 28,522 and at December 31, 1993 and 1992 were avail- June 30 278,100 40,722 21,397 able in the amounts of $ 537 million and $ 521 September 30 320,409 52,898 33,658 million, respectively. Commitment fees of Oecember 31 301,166 63,031 45,736 approximately 3/16 of 1% a year are paid to the 1992 banks to maintain the lines of credit. Harch 31 301,134 54,022 35,035 June 30 280,421 43,535 24,844 September 30 311,080 45,323 24,384

12. FAIR VALUE OF FINANCIALINSTRUMENTS: Oecember 31 304,120 52,640 39,685 Fourth quarter 1992 net income includes $ 13 The carrying amounts of cash and cash equiva- million comprised of interest on prior years'ederal lents, accounts receivable, short-term debt, and income tax refunds and cost reductions due to accounts payable approximate fair value because of favorable benefit plans experience.

the short-term maturity of these instruments. At 28

INDIAAIAMICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS 1993 1992 1991 990 ~989 OPERATIN6 REVENUES (in thousands):

Retail:

Residential:

'Without Electric Heatin9 $ 205,315 $ 209,682 $ 206,257 $ 192,822 $ 195,504 With Electric Heating 97 560 90 553 93 209 00 710 95 987 Total Residential 302,883 308,235 299,546 281,540 291,491 Co()n)ercial 220,938 228,285 216,303 205,025 205,918 industrial 250,939 267,643 241,858 244,773 251,279 Miscellaneous 5 593 11 012 12 120 ll 799 12 021 Total Retail 780,353 815,175 769,827 743,137 760,709 Wholesale (sales for resale) 404 910 369 379 436 003 510 000 361 962 Total Revenues from Energy Sales 1,185,263 1,184,554 1,205,910 1,261,217 1,122,671 Provision for Refunds of Revenues Collected in Prior Years ~755) ~4038) 5 176 ~5176)

Total Net of Provision for Refunds 1,184,508 1,180,516 1,211,086 1,256,041 1,122,671 Other 10 135 16 239 14 701 15 473 Total Operating Revenues 1 202 643 1 196 755 ~l225 867 1 271 514 ~)135 507 SOURCES ANO SALES OF ENER6Y (in millions of kilowatt-hours):

Sources:

Net Generated:

Fossil Fuel 12,236 11,597 12,109 14,451 10,634 Nuclear Fuel 16,313 6,418 15,524 11,115 12,094 Hydroelectric 106 100 109 ~17 ~08 Total Net Generated 28,655 18,115 27,742 25,693 22,836 Purchased and Power Pool ~4879 ~9342 ~5237 ~7983 ~7630 Total Sources 33,534 27,457 32,979 33,676 30,466 Less: Losses, Company Use, Etc. ~1349 ~1466 ~454 ~1633 ~1647 Net Sources ~32 185 ~25 991 ~31 525 ~32 043 ~28 819 Sales:

Retail:

Residential:

Without Electric Heating 3,178 3,001 3,166 2,955 2,975 With Electric Heating ~1706 ~1633 ~1625 ~1525 ~1627 Total Residential 4,884 4,634 4,791 4,480 4,602 Comercial 3,977 3,747 3,726 3,536 3,519 Industrial 6,025 5,685 5,382 5,452 5,512 Miscellaneous 83 194 233 229 236 Total Retail 14,969 14,260 14,132 13,697 13,869 Wholesale (sales for resale) ~17 216 ~11 731 ~17 393 ~18 346 ~14 950 Total Sales ~32 185 ~25 991 ~31 525 ~32 043 ~28 819 29

OPERATING STATISTICS (Concluded) 1993 992 ~99 1990 AVERAGE COST OF FUEL CONSUMED (in cents):

Per Million Btu:

Coal 130 136 141 145 164 Nuclear 36 54 48 58 61 Overall 72 103 84 105 106 Per Kilowatt-hour Generated:

Coal 1.27 1.34 1.39 1.42 1.62 Nuclear .40 .61 .53 .64 .67 Overall .77 1.08 .91 1.08 1.11 RESIDENTIAL SERVICE - AVERAGES:

Annual Kwh Use per Customer:

Total 10,564 10,107 10,539 9,944 10,303 With Electric Heating 17,989 17,513 17,703 16,897 18,337 Annual Electric Bill:

Total $ 655.07 $ 672.31 $ 659.01 $ 624.95 $ 652.64 With Electric Heating $ 1,028.82 $ 1,056.91 $ 1,016.24 $ 983.28 $ 1,081.78 Price per Kwh (in cents):

Total 6.20 6.65 6.25 6.28 6.33 With Electric Heating 5.72 6. 04 5.74 5.82 5.90 NUMBER OF CUSTOMERS:

Year-End:

Retail:

Residential:

Without Electric Heating 369,385 366,835 364,154 362,645 360,040 With Electric Heating 95 795 94 175 92 657 91 179 89 881 Total Residential 465,180 461,010 456,811 453,824 449.921 Co2nnercial 53,081 52,542 51,491 50,994 50,043 Industrial 5,157 5,000 4,847 4,801 4,792 Miscellaneous 1 783 1 751 2 226 2 160 2 168 Total Retail Wholesale (sales for resale)

Total Customers 525,201

~525 56 257 520,303

~520 53 356 515.375

~575 53 428 511,779 511 834 55 ~5 506,924 506 975 30

DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED STOCK By Quarters (1993 and 1992) 1993 - uarters 1992 - uarters 1st 2nd 3rd 4th 1st hand 3rd 4th CUMULATIVE PREFERREO STOCK

($ 100 Par Value) 4-1/BX Series Oividends Paid Per Share $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 Harket Price - $ Per Share (MSE) - High

- Low 4.56K Series Oividends Paid Per Share $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low)

4. 12K Series Oividends Paid Per Share $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High 51 51-1/2 55-1/4 58-1/2 47 47 48 50

- Low 48 48 51 54-3/4 39-1/2 47 47 48 5.90K Series (a)

Dividends Paid Per Share $ 0.9342 Market Price - $ Per Share (OTC)

Ask (high/low)

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

Oividends Paid Per Share $ 0.5382 Harket Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6-7/BX Series (b)

Oividends Paid Per Share $ .84 $ 1.71875 $ 1.71785 $ 1.71875 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 7.08K Series Oividends Paid Per Share $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 Market Price - $ Per Share (NZSE) - High 92 96 99-5/8 100-1/8 88-1/2 88-1/2 92 92

- Low 89-1/4 91 96-3/8 95 83-1/4 84-1/2 85-1/2 89 7.76K Series (c)

Oividends Paid Per Share $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 Market Price - $ Per Share (MYSE) - High 102-1/4 102 104 102-3/4 95-3/4 96-1/8 98-3/4 98-1/4

- Low 95-3/4 98 100 98-1/2 90-1/2 92-1/4 93-1/2 93 31

DIVIDENDS AND PRICE RANGES OF CUMULATIVEPREFERRED'TOCK By Quarters (1993 and 1992) (Concluded) 1993 - uar ters 1992 - uarters 1st 2nd 3rd 4th gnd ~rd 4th CUHU ATIV PR FERR 0 STOCK

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

Dividends Paid Per Share $ 2.17 $ 2.17 $ 2.17 $ 1.8807 $ 2.17 $ 2.17 $ 2.17 $ 2.17 Market Price - $ Per Share (NYSE) - High 103 103-1/2 104 103 102-1/4 102 103 103

- Low 100 101 101 101-1/4 98-1/2 99 100-1/4 100

($ 25 Par Value)

$ 2.15 Series (e)

Dividends Paid Per Share $ 0.5375 $ 0.5375 $ 0.5375 $ 0.2628 $ 0.5375 $ 0.5375 $ 0.5375 $ 0.5375 Market Price - $ Per Share (NYSE) - High 27-1/2 27-1/4 27-3/8 26-1/2 26 26 27-1/4 27

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

$ 2.25 Series (f)

Dividends Paid Per Share $ 0.375 $ 0.5625 $ 0.5625 $ 0.5625 $ 0.5625 Market Price - $ Per Share (NYSE) - High 26-3/4 27-1/4 27-1/4 27-1/2 27-1/4

- Low 25-1/2 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 and do not represent actual transactions.

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 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 VI RG I NIA KENTUCKY 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 INDIANA MICHIGAN 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 After Taxes 138.4 Less Dividends Paid 118.3 Retained Earnings 20.1 Adjustments:

Depreciation And Amortization 162.0 Deferred Operating Costs (23.1)

Deferred Federal Income Taxes and Investment Tax Credits (28.4)

AFUDC (2.3)

Other (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