ML17331A282

Impr 1992 Annual Rept

ML17331A282
Person / Time
Site:	Cook
Issue date:	12/31/1992
From:	Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:09091, AEP:NRC:9091, NUDOCS 9304220064
Download: ML17331A282 (40)

Text

ACCELERA'I' DOCUMENT DIST tBUTION SYSTEM REGULAT INFORMATION DISTRIBUTIO YSTEM (RIDS)

ACCESSION NBR:9304220064 DOC.DATE: ~jh2fYPf&

NOTARIZED: NO DOCKET FACIL:50-315 Donald C.

Cook Nuclear Power Plant, Unit 1, Indiana M

05000315 50-316 Donald C.

Cook Nuclear Power Plant, Unit 2, Indiana M

05000316 AUTH.NAME AUTHOR AFFILIATION FITZPATRICK,E.

Indiana Michigan Power Co. (formerly Indiana

& Michigan Ele RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"IMPR 1992 Annual Rept."

W~930416 Itt.

DISTRIBUTION CODE:

M004D COPIES RECEIVED:LTR 2 ENCL TITLE: 50.71(b)

Annual Financial Report NOTES:

SIZE:

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1 1

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

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1 EG FILE 01 1

1 NOTE TO ALL"RIDS" RECIPIENTS:

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indiana Michigan Power Company P.O. Box 16631..

'olumbus;OH 43216 AEP:NRC:0909I 10 CFR 50.71(b) 6 140.21(e)

Donald C. Cook Nuclear Plant Units 1 and 2

Docket Nos.

50-315 and 50-316 License Nos.

DPR-58 and DPR-74 FINANCIAL INFORMATION FOR INDIANAMICHIGAN POWER COMPANY U. S. Nuclear Regulatory Commission Attn:

Document Control Desk Washington, D.C.

20555 Attn:

T. E. Murley April 16, 1993

Dear Dr. Murley:

Enclosure 1 contains the Indiana Michigan Power Company's (IGM) annual report for 1992.

Enclosure 2

contains a

copy of I@M's projected cash flow for 1993.

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

E. E. Fitz rick Vice President dgr Enclosures cc:

A. A. Blind Bridgman J.

R. Padgett G. Charnoff A. B. Davis Region IZZ NRC Resident Inspector Bridgman NFEM Section Chief r

9304220064 92i23i PDR ADOCK 050003i5 X

PDR

ENCLOSURE 1 TO AEP:NRC:0909I INDIANA MICHIGAN POWER COMPANY'S 1992 ANNUAL REPORT

Indiana Michigan Power Company 1992 Annual Report

Contents Company

Background

Directors and Officers of the Company Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations and Financial Condition Independent Auditors'eport Consolidated Statements of Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Notes to Consolidated Financial Statements Operating Statistics Dividends and Price Ranges of Cumulative Preferred Stock

INDIANAMICHIGANPOWER COMPANY One Summit Sq P.O. Box 60, Fort Wayne, Indiana 46801 Company Background INDIANAMIGHIGANPowER C0MpANY (the Company), a subsidiary of American Electric Power Company, Inc.

(AEP), is engaged in the generation,

purchase, transmission, distribution and sale of electric power. The Company was organized under the laws of Indiana on February 21, 1925, and is also authorized to transact business in Michigan and West Virginia. Its principal executive offices are in Fort Wayne, Indiana.

Effective February 29, 1992, Michigan Power Company, another subsidiary of AEP, was merged into the Company.

The Company has two wholly owned subsidiaries; they are Blackhawk Coal Company and Price River Coal Company, which 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 generating plants of the Company and its affiliates. RTD also provides some barging services to unaffiliated companies.

The Company serves approximately 520,000 customers in northern and eastern Indiana and a portion of southwestern Michigan. Among 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.

In addition, the Company supplies wholesale electric power to other electric utilities, municipalities and electric cooperatives.

The Company has 4,759 megawatts of generating capacity which comes from two nuclear units, seven coal-fired units, one gas unit and 33 hydro units. The Company's generating plants and important load centers are interconnected by a high-voltage transmission network. This network in turn is interconnected either directly or indirectly with the following other AEP System companies to form a single integrated power system:

AEP Generating Company, Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company, Kingsport Power Company, Ohio Power Company and Wheeling Power Company. The Company is also interconnected with the following unaffiliated utilities: Central Illinois Public Service Company, The Cincinnati Gas 8 Electric Company, Commonwealth Edison Company, Consumers Power Company, Illinois Power Company, Indianapolis Power 8 Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power 8 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). The Company shares generating and transmission capacity and the cost of such capacity with the other affiliated AEP System companies through the AEP System Power Pool and AEP Transmission Agreement. The Company also shares in wholesale energy sales made by the Power Pool.

0,

Directors MARKA. BAILEY PETER J. DEMARIA(a)

RICHARD E. DISBROW WILLIAMN. D ONOFRIO E. LINN DRAPER, JR.

ALLEN R. GLASSBURN (b)

WILLIAMJ. LHOTA GERALD P. MALONEY RICHARD C. MENGE WILLIAMF. POHLMAN (C)

RONALD E. PRATER (C)

DALE M. TRENARY (b)

WILLIAME. WALTERS DAVID H. WILLIAMS,JR. (d)

Officers RICHARD E. DISBROW Chairman of the Board and Chief Executive Officer RICHARD C. MENGE President and Chief Operating Officer MARKA. BAILEY Vice President PETER J. DEMARIA Vice President and Treasurer WILLIAMN. D'ONOFRIO Vice President A. JOSEPH DOWD Vice President E. LINN DRAPER, JR.

Vice President EUGENE E. FITZPATRICK Vice President RICHARD F. HERING Vice President WILLIAMJ.

LHOTA Vice President GERALD P. MALONEY Vice President DAVID H. WILLIAMS,JR. ((j)"

Vice President JOHN F. DILORENZO, JR.

Secretary ELIO BAFILE Assistant Secretary'and Assistant Treasurer JEFFREY D. CROSS Assistant Secretary CARL J. Moos Assistant Secretary JOHN B. SHINNOCK Assistant Secretary LEONARD V. ASSANTE Assistant Treasurer BRUCE M. BARBER Assistant Treasurer GERALD R. KNORR Assistant Treasurer As of January 1, f993 the current directors and officers of Indiana Michigan Power Company were employees ofAmerican Electric Power Service Corporation with eight exceptions: Messrs.

Bafile,'Bailey, D'Dnofrio, Glasshurn, Menge, Moos, Trenary, and Walters, who were employees of Indiana Michigan Power Company.

(a) Elected December 31, 1992 (b) Elected April 28, 1992 (c) Resigned April 28, 1992 (d) Resigned December 31, 1992

. ~

1 Selected Consolidated Financial Data INDIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES Year Ended December 31, 1992 1991 1990 (in thousands) 1989 1988 INCOME STATEMENTS DATA:

OPERATING REVENUES OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME (LOSS)

INCOME BEFORE INTEREST CHARGES.......

INTEREST CHARGES NET INCOME

'PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE To COMMON STOCK 195,520 227,289 14,115

~3,721) 201,491 7,557 209,048 90.657 118,391 15,587 213,983 32,737 217,744 43,473 223,568 86,636 209,635 85,687 246,720 107,483 261,217 108,320 123,948 15,417 136,932 15,417 139,237 18,048 152,897 18,848 108,531 121,515 102,804 121,189 134,049

$1,196,755

$1,225,867

$1,271,514

$1,135,587

$1,066,659 1,001,235 998,578 1,070,023 921,604 848,915 1992 1991 December 31, 1990 (in thousands) 1989 1988 BALANCESHEETS DATA:

ELECTRIC UTILITY PLANT ACCUMULATED DEPRECIATION AND AMORTIZATION NET ELECTRIC UTILITY PLANT TOTAL ASSETS

$4,266,480

$4,135,820

$4,066,227

$3,969,602

$4,459,334 1,631,438 1,521,349 1,421,285 1,309,072 1,233,761

$2,635,042

$2,614,471

$2,644,942

$2,660,530

$3,225,573

$3,612,464

$3,447,430

$3,463,919

$4,085,591

$4,004,016 COMMON STOCK AND PAID-IN CAPITAL...

RETAINED EARNINGS TOTAL COMMON SHAREOWNER S Eounv:.

CUMULATIVEPREFERRED STOCK:

NOT SUBJECT TO MANDATORY REDEMPTION SUBJEOT TO MANDAT0RY REDEMPTI0N (a)

TOTAL L0NG-TERM DEBT (a)

OBLIGATI0Ns UNDER CAPITAL LEAsfs (a)

TOTAL CAPITALIZATIONAND LIABILITIES...

782,741 782,741 782,741 782,741 846,895 171,309 169,243 150,408 162,213 165,226 954,050 951,984 933,149 944,954

$1,012,121 197,000 197,000 197,000 197,000 197,000 18,030 25,030 197,000 197-,000 197,000 215,030 222,030

$1,211,623

$1,130,709

$1,133,833

$1,532,736

$1,585,220 3

126689 8

102,985 8

133.447 8

123,361 8

168.196

$3,612,464

$3,447,430

$3,463,919

$4,085,591

$4,004,016 (a) Including portion due within one year.

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

~

Results of Operations IIet Income Declines Net income declined 9.5% to $124 million in 1992 after increasing 16% in 1991 to $137 million. The decrease in1992 was primarily due to reduced availability of the nuclear units and reduced demand for wholesale energy, partly offset by increased nonoperating income for nonrecurring items. Both nuclear units.were out of service for scheduled refueling and one unit experienced an extended, unscheduled, non-refuel-ing related outage. The increase in 1991 net income reflected reductions in fuel expense, energy purch'ases and mainte-nance costs, as neither of the Donald C. Cook Nuclear Plant (Cook Nuclear Plant) units were refueled during 1991, and decreased interest charges.

Outlook The Company, as a member of the AEP System, is entering a new era in the electric utilityindustry and in the conduct of its business.

For the first time in over 50 years, the AEP System is'not constructing any new generating capacity. In addition, management is currently in the process of down-sizing certain of the System's operations including the Amer-ican Electric Power Service Corporation (AEPSC).

AEPSC provides services at cost to the AEP operating companies including the Company. A reduction in AEPSC costs should reduce the cost of services provided to the Company.

The electric utility industry is expected to experience significant changes as a result of the National Energy Policy Act of 1992 (Energy Act) which eases restrictions on independent power producers and allows the Federal Energy Regulatory Com-mission (FERC) to mandate transmission access with the goal of increasing competition in the generation of electricity and the supply of bulk power to major wholesale customers.

The many strengths of the AEP System should allow Indiana Michigan Power Company (l&M) to compete vigorously in this new environment. The generating capacity of the AEP System is expected to be adequate to the end of the century, postponing the need to embark on an expensive construction program to build new generation. Generating plants-built at low cost, operated efficiently and well maintained-make the AEP System a low-cost producer of energy. To maintain our competitive advantage, management has undertaken efforts that focus on reducing the work force by improving produc-tivity and eliminating duplicative or unnecessary work.

One such effort involves a planning and scheduling pro-gram being implemented in the transmission and distribution (T&D) line functions. This program, designed to increase productivity, adopts the latest planning, scheduling and time management techniques and increases management skills of T&Dsupervisors. The program is expected to enable the Com-pany to maintain its facilities with fewer T&D personnel in the future.

Management is committed to cost-effective Demand Side Management (DSM), conservation and other efforts to delay the addition of new, higher cost generation and transmission facilities. For many years l&M has encouraged the efficient use ofelectricity through promotion of energy efficient electric equipment such as the heat pump, geothermal electric heating

systems, and off-peak thermal storage heating and hot water appliances.

The Company is financing and participating in efforts to develop the TranstexT Advanced Energy Manage-ment System which allows residential customers to modify their energy usage according to time-of-day pricing.

In addition to meeting the challenge of competition in the generation of electricity and its sale to wholesale customers, I&Mfaces many challenges that could adversely affect finan-cial performance and its ability to meet financial obligations and commitments. While management believes the Company is equipped to meet the challenges, uncertainties that could adversely affect future financial performance include the abil-ity to recover cost of service on a timely basis, especially:

~ the cost of compliance with the Clean Air Act Amend-ments of1990 and other environmental costs under pres-ent and future laws and regulations; and

~ the full cost of decommissioning its two nuclear gener-ating units and the disposal of spent nuclear fuel.

Management will be facing the possibility of new federal taxes. The Clinton Administration has proposed an energy tax and an increase in the corporate income tax rate as a means of curbing the federal deficit. Others have proposed a tax on carbon, dioxide erriissions and other actions to reduce "green-house" gases and address the as of yet unproven "global warming" problem. These proposals, if enacted, could have an adverse effect on the economy of the service area and financial performance.

Future results of operations depend on the economic health of the service territory, weather patterns and the ability of the American Electric Power System Power Pool (Power Pool) to make wholesale energy sales which are dependent on the weather and the supply and demand for wholesale bulk energy. While many of these items are not generally within management's control, every effort will be made to protect the economy of the Company's service territory from unnec-essary and unwise new tax and environmental laws and reg-ulations, to market available capacity and to continue to control operating costs.

. ~

t INDIANAMICHIGANPOWER COMPANY AND SIJBSIDIARIES Retail:

Price variance Volume variance 42.3

$ (0.9) 3.0 27.6 45.3 5.9 26.7

3.6 Whoiesaie

~

Price variance Volume variance 75.2 (55.1)

(141.9)

(26.9)

(66.7) (15.3)

(82.0) (15.8)

Other Operating Revenues...........

(7.7) 9.7 Total S (29.1)

(2.4) $(45.6)

(3.6)

The substantial retail and wholesale price variances in 1992 resulted from the operation of fuel adjustment clauses. Under the retail jurisdictional fuel clauses revenues were accrued representing future recovery of higher fossil fuel generation costs which were incurred during the Cook Nuclear Plant outages.

The 1992 increase in retail sales volume reflects growth in industrial sales partially offset by the effects of mild summer weather on residential service. The substantial decrease in wholesale volume in 1992 was caused by lower sales to the Power Pool due to the Cook Nuclear Plant outages and reduced wholesale sales by the Power Pool. The decline in the wholesale Power Pool sales in 1992 reflected mild weather and price competition in the wholesale market.

The increase in 1991 retail sales volume reflected warmer spring and summer weather partly offset by the transfer of a major industrial customer to a local distribution utilitywhich the Company serves at wholesale. The decline in wholesale volume in 1991 reflected a substantial decrease in wholesale Power Pool sales offset in part by the above noted transfer.

Operating Revenues and Energy Sales Decline Operating revenues declined $29 million in 1992 following a decline of $46 million in 1991. The 1992 decline was attrib-utable to the Cook Nuclear Plant outages which reduced the amount of energy available for sale to the Power Pool coupled with reduced wholesale sales by the Power Pool. The decline in 1991 revenues was due to price competition in the whole-sale energy market and a decline in wholesale Power Pool sales to unaffiliated utilities which began in the fourth quarter of 1990.

The reductions in revenues are analyzed as follows:

Increase (Decrease)

From Previous Year 1992 1991 (dollars in millions)

Amount

'/o Amount

/o (dollars in millions)

Amount

/o Amount

/o

$(57.5)

(22.9) $(25.4 (9.2) 57.8 47.1 (40.1 (24.7) 17.8 7.2 (1.9 (0.8) 52.9 44.4 (17.8)

(13.0)

Fuel Purchased Power..............

Other Operation...............

Maintenance Depreciation and Amortization................

1.1 0.8 1.2 0.9 Deterred Operating Costs (net)......

(47.9)

II.M.

Taxes Other Than Federal Income Taxes...............

(0.6)

(0.9) 7.1 12.7 Federal Income Taxes...".........

(20.9)

(45.1) 5.5 13.4 Total 2.7 0.3

$(71.4)

(6.7)

N.M. Not Meaningful The Cook Nuclear Plant outages reduced nuclear generation for 1992 by 59/o contributing to a 35'/o overall decline in generation compared with the prior year. The reduction cou-pled with a 4'/o lower average cost of fossil fuel caused fuel expense to decline significantly in 1992. The reduction in fuel expense in1991 occurred, even though generation increased by 8/o, because of availability of the nuclear units with their lower fuel cost.

A Power Pool long-term contract for the sale of up to 560 mw of power to an unaffiliated utility expired on December 31, 1990. Also during 1990 the Power Pool sold significant quantities of energy to an unaffiliated utilityunder a series of short-term wholesale contracts which expired at the end of 1990. Management has been able to negotiate only a limited number of additional long-term sales, thereby only partially replacing the terminated long-term contract. Efforts to make short-term Power Pool sales have had limited success due to the highly competitive nature of the wholesale market and its dependence on factors not generally within management's control. The level of future wholesale sales willdepend on the market price for wholesale power, availability of unaffiliated generating

capacity, the economy and weather patterns.

Future results of operations will be affected by the ability to make wholesale sales at a profit or, if such sales are not forthcoming, the Company's ability to raise retail rates.

Operating Expenses Increase Operating expenses increased marginally in 1992 even though generation declined due predominantly to the refueling outages at the Cook Nuclear Plant.

In 1991 operating expenses declined nearly 7/o due to reduced fuel expense, energy purchases and maintenance expenses reflecting the continued service of both nuclear units during the year after scheduled refueling outages at both units in 1990. Changes in the components of operating expenses were as follows:

Increase (Decrease)

From Previous Year 1992

'I991

The increase in purchased power expense in 1992 reflects the increase in energy received from the Power Pool because of the Cook Nuclear Plant outages.

The decrease in 1991 reflected the decline in wholesale power demand discussed above.

Certain operations and maintenance procedures are per-formed only when a nuclear unit is out of service. The sig-nificant increases in other operation and maintenance expenses are predominantly attributable to the refueling and unscheduled non-refueling outages at Cook Nuclear Plant.

However, the impact on earnings from refueling outages was mitigated through the implementation of levelized accounting in January 1992.

Levelized accounting spreads the incre-mental costs of refueling over the time the unit burns the fuel so that an average number of refuelings are reflected in each year's expense.

The Company received regulatory approval to defer incremental nuclear refueling outage costs and to amortize them from the start of an outage until the beginning of the next outage. Although the earnings impact of refueling outages are levelized, large fluctuations still appear in the other operation and maintenance expense income statement lines since the deferral is included in "Deferred Operating Costs" on the Consolidated Statements of Income. At Decem-ber 31, 1992, the Company had deferred $47.2 million of incremental refueling outage costs net of amortization. Amor-tization of these costs willoccur in 1993 and part of 1994.

Taxes other than federal income taxes increased in 1991 primarily due to the effect of a property tax over accrual adjustment recorded in 1990 and a provision recorded in 1991 for an audit assessment of Indiana gross receipts tax on payments received under an AEP System transmission equal-ization agreement.

The decrease in federal income taxes attributable to oper-ations in 1992 was primarily due to the decrease in pre-tax operating book income. In 1991 an increase in pre-tax book income was the principal reason for the increase in federal income taxes.

Nonoperating Income and Interest Charges Nonoperating income rose significantly in 1992 mainly due to interest income recorded on tax refunds receivable from the Internal Revenue Service in connection with the settlement of audits of prior years'ax returns. Further contributing to the 1992 increase was the partial reversal of a provision recorded in 1991 for a royalty dispute with the state of Utah concerning prior coal-mining operations. The 1991 decline in nonoperating income reflected the above provision and the write-off of the costs associated with an expired federal coal lease of a currently inactive mining subsidiary.

Interest expense declined slightly even though the Com-

'any issued an additional $80 millionof long-term debt during 1992 as the interest on the new debt was offset by the refi-nancing of higher cost installment purchase contracts (IPC) and lower interest rates on a variable rate IPC. The decline in interest expense in 1991 was due to the retirement of debt in February 1990 with proceeds from the sale of Rockport Plant Unit 2 (Rockport 2), the refinancing of IPCs at lower rates and a lower average interest rate on a variable rate IPC.

Liquidity and Capital Resources Construction Spending Gross plant and property additions were $176 million in 1992 and $149 million in 1991. The increase was due to the acquisition of nuclear fuel in connection with the Cook Nuclear Plant refueling. Construction expenditures for the next three years are estiniated at $458 million. The funds for construc-tion of new facilities and improvement of existing facilities come from a combination of internally generated funds, short-term and long-term borrowings and investments in common equity by the Company's parent, AEP. All of the construction expenditures for the next three years are expected to be financed internally.

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Capital Resources The Company generally issues short-term debt to provide for interim financing of construction and capital expenditures in excess of available internally generated funds. At December 31, 1992, unused short-term lines of credit of $521 million shared with other AEP System companies were available. A charter provision limits short-term borrowings to $141 mil-lion. Periodically, outstanding short-term debt is reduced through the issuance of long-term debt and preferred stock securities and investments in its common equity by AEP.

The Company is restricted, by the terms of its mortgage and preferred stock, from issuing additional long-term debt or preferred stock unless it meets certain earnings tests. Gen-erally, in order to issue long-term debt without refunding an equal amount of existing debt, pre-tax earnings must be equal to at least twice annual interest charges on long-term debt after giving effect to the new debt. To issue additional pre-ferred stock, after-tax gross income must be at least equal to one and one-half times annual interest and preferred dividend requirements after giving effect to the new preferred stock.

Consequently, earnings performance determines the ability to finance. At December 31, 1992, long-term debt and pre-ferred stock coverage ratios were 3.55 and 2.06, respectively.

Concerns and Contingencies Environmental Costs Clean AirAct Amendments of 1990 The Clean AirAct Amendments of 1990 require, among other, things, substantial reductions in sulfur dioxide and nitrogen oxide emissions from electric generating plants. The law establishes a strict timetable for compliance, with Phase I reductions to be accomplished by1995 and Phase II reduc-tions to be achieved by the year 2000.

The Company plans to fuel switch at its Tanners Creek Unit 4 to meet Phase I requirements and has announced the retire-ment of the Breed Plant no later than the end of 1994. Addi-tional costs will be incurred to.comply with Phase II requirements at the AEP System's coal-fired generating plants. Should the Company be unable to recover its share of the AEP System compliance costs, itwould have an adverse impact on results of operations and financial condition.

Hazardous Material By-products from generation of electricity include a

number of non-hazardous and hazardous materials such as

ash, slag,

sludge, low level radioactive waste and spent nuclear fuel. In addition, the Company's generating plants and transmission and distribution facilities have used asbes-tos, poiychlorinated biphenyls (PCBs) and other hazardous materials.

Significant costs are incurred for the handling, transportation, storage and disposal of hazardous and non-hazardous materials. Additional costs to comply with new laws and regulations if and when enacted could be incurred.

The Superfund created by the Comprehensive Environ-mental Response Compensation and LiabilityAct (CERCLA) addresses cleanup of hazardous waste disposal sites and authorizes the EPA to administer the clean-up programs. The Company has been named by EPA as a "potentially respon-sible party" (PRP) for six sites and has received information requests for three other sites. The Company has also been identified as a PRP under illinois law for one additional site.

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

The Company and several unaffiliated companies have been named as defendants in two separate cost recovery lawsuits by unaffiliated parties who are completing remediation activities at two CERCLA sites.

Although the potential liabilityassociated with each PRP has been and must be evaluated individually, several general statements can be made regarding the PRP notices received.

Allegations of disposal of hazardous substances are often unsubstantiated.

Quantities of material disposed of were gen-erally minor and/or non-hazardous.

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

Therefore, present estimates do not anticipate material clean up costs. However, iffor reasons presently unknown, material costs are incurred for clean up, results of operations and financial condition would be adversely impacted unless the costs can be recovered from insurance carriers and/or customers.

The Company maintains insurance against damage and liabilityfrom its Cook Nuclear Plant. In the event of a nuclear incident at the Cook Nuclear Plant or any nuclear plant in the United States, the insurance program would require payment of significant retrospective premiums and could involve addi-tional uninsured costs.

Unless costs incurred in connection with a nuclear incident are recovered from insurance carriers and/or customers, results of operations and financial condi-tion would be adversely impacted.

Cook Nuclear Plant decommissioning obligations are sig-nificant. A decommissioning provision is recorded commen-surate with recovery. through rates.

Regulators have authorized recovery of nuclear decommissioning costs over the life of Cook Nuclear Plant based on an independent 1989 study which estimated decommissioning costs at between

~ $330 million and $369 million. A new study performed in 1991 estimated the cost of decommissioning to range from

$588 million to $1,102 million. The substantial increase is primarily due to the anticipated need to store spent nuclear fuel at the plant site for an extended period of time after the plant ceases operation, delaying the commencement of dis-mantling activities. A request to increase the recovery of decommissioning costs is pending in the Indiana jurisdiction and management plans to seek similar increases in the Mich-igan and FERC jurisdictions. Management periodically re-evaluates decommissioning costs and seeks regulatory approval to recover such amounts as necessary.

Failure to fully recover decommissioning costs would adversely affect results of operations and possibly financial condition.

In October 1992 the Energy Act was signed into law. The Energy Act contains a provision to fund the decommissioning and decontamination of U.S. Department of Energy's (DOE) existing uranium enrichment facilities from a combination of sources including assessments against electric utilities which purchased nuclear fuel enrichment services from DOE facili-ties. The Company willbe assessed approximately $48 million subject to inflation adjustments under the law payable annually over 15 years.

This amount was recorded as a

deferred charge concurrent with the recording of the liability.

The first year estimated assessment of $3.25 million will be recognized as a fuel expense in 1993, and, under the provi-sions of the Energy Act, recovery will be sought in the next fuel rate adjustment proceedings.'ow Level Radioactive Waste Disposal A federal law established regional compacts which states can enter to provide for the disposal of low level radioactive waste. The state of Michigan, where the Cook Nuclear Plant is located, lost its membership in the Midwest Compact for failure to meet host state obligations. As a result, the Cook Nuclear Plant has been denied access since late 1990 to cur-rently operating low level radioactive waste disposal sites and its low level radioactive waste is being stored at the plant site.

The on-site storage facilityis expected to provide ample tem-porary storage space until the year 2002. The Company is unable to estimate what additional costs, if any, it may incur as a result of the revocation of Michigan's membership in the Midwest Compact.

Other New Environmental and Health Concerns The United States has signed and ratified a United Nations treaty that will require, when effective, the United States to commit to a process of achieving the aim of reducing the emission of greenhouse gases, including carbon dioxide. The U.S. Government has released for public comment a draft of such a plan which emphasizes reductions in the use of fossil fuel, the largest source of carbon dioxide. One option for discouraging carbon dioxide emissions is a carbon or energy tax. Any restriction on carbon dioxide emissions, whether by regulation, taxation or other means, would adversely affect results of operations and financial condition unless the result-ant cost can be recovered from customers.

In addition, any program to control carbon dioxide emissions would probably impose substantial costs on industrial customers.

In recent years there has been considerable discussion of the effects on public health of electric and magnetic fields (EMF) from transmission and distribution facilities. Manage-ment is concerned that new laws may be passed or new regulations promulgated without sufficient scientific study and evidence.

The Company continues to work to support efforts to properly study EMF so as to define the extent, if any, to which they pose a threat to the environment and public health before new restrictions are imposed. Should Congress enact legislation to control EMF, results of operations and financial condition would be adversely affected unless the cost of compliance can be recovered from customers.

Regulatory Matters In April 1992 a request for an increase of $44.8 million in annual rates was filed with the Indiana UtilityRegulatory Com-mission (IURC) to recover increased operating costs. In Sep-tember 1992 the Office of UtilityConsumer Counselor (UCC) and other intervening parties filed testimony and exhibits opposing the Company's rate increase.

The UCC recom-mended a rate decrease.

The IURC has concluded hearings and a rate order is expected in 1993. A significant portion of the difference between the Company's request and the UCC's recommended decrease is related to depreciation rates. Ifthe IURC were to adopt the depreciation rates proposed by the UCC, there would be no immediate effect on earnings but cash flow would be reduced.

Unless the Company receives adequate and timely rate relief, results of operations and financial condition would be adversely affected.

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES As previously discussed and as described in Note 1 of the Notes to Consolidated Financial Statements, the Company practices levelized accounting for incremental nuclear refuel-ing outage costs. The Company is currently requesting recov-ery of a levelized amount of such costs associated with nuclear refueling outages in its Indiana rate filing discussed above and will request recovery in its next Michigan and FERC base rate filings.

A FERC administrative law judge (ALJ) issued an initial decision in June 1990 regarding a complaint filed by a whole-sale customer concerning the reasonableness of the cost of coal acquired from an unaffiliated supplier who leased the Company's western low sulfur coal-mining properties and the coal transportation charges of affiliates. The initial decision would have required the Company to refund to wholesale customers

$25 million related to the unaffiliated coal costs and an undetermined amount for affiliated transportation charges.

In February1993 the FERC reversed the ALJ's deci-sion and dismissed the complaint.

Outage at Nuclear ilnit The Company experienced an extended, unscheduled, non-refueling related outage at Cook Nuclear Plant Unit 2 resulting in additional replacement power costs. Under its fuel recovery mechanisms,

$38 million of fuel revenues were accrued through December1992 related to the incremental purchased power costs and other replacement power costs incurred dur-ing refueling outages of both nuclear units. In the Indiana jurisdiction the accrued revenues are being collected during the first six months of 1993. Recovery in the Michigan juris-diction will be sought in the next power supply recovery proceeding.

Merger Michigan Power Company (MPCo) was merged into the Company on February 29, 1992 after receiving all required regulatory approvals.

The merger was accounted for as a pooling-of-interests and did not significantly impact results of operations or financial condition. Pertinent financial infor-mation for the Company and MPCo before the merger is shown in Note 1 of the Notes to Consolidated Financial Statements.

Effects of Inflation Inflation affects the cost of replacing utilityplant as well as the cost of operating and maintaining such plant. The rate-making process generally limits recovery to the historical cost of assets resulting in economic losses when inflation effects are not recovered from customers on a timely basis.

Eco-nomic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.

New Accounting Standards The Financial Accounting Standards Board (FASB) has issued three new accounting standards which affect the Com-pany. Statement of Financial Accounting Standards No. 109 Accounting forIncome Taxes, (SFAS 109) requires the liability method of accounting for income taxes effective January 1, 1993; In1993 under SFAS109 the Company recorded approx-imately $260 million of net additional deferred income tax liabilities on temporary differences previously flowed through and adjusted previously recorded deferred taxes to the level required at the current statutory tax rate. A corresponding net regulatory asset of $254 million was recorded for the portion of the additional deferred taxes which are recoverable from customers.

The new standard was implemented in January 1993 on a prospective basis with only a minor adverse effect on results of operations. As permitted by SFAS 109 the 1992 finanicial statements do not reflect the implementation of SFAS 109.

SFAS 106, Employers'Accounting forPostretirement Ben-efits Other Than Pensions, required the Company to change its accounting for post-retirement benefits other than pen-sions from a pay-as-you-go method to an accrual method effective January 1, 1993. This standard permits recognition of the prior service costs as a transition obligation over 20 years.

The expense accrual required by the new standard, including recordation over 20 years of the Company's

$83 million transition obligation, is expected to be $12.3 million for 1993 versus

$4.4 million on the prior pay-as-you-go method. Regulatory commission approval was received in the Michigan and FERC jurisdictions to defer, under the provisions of SFAS 71, any increased costs for which recovery is not provided currently. The Company plans to seek recovery of the increased expense and related deferrals in its next base rate filings. The current Indiana rate filing seeks recovery of incremental SFAS 106 accruals. Should recovery of the SFAS 106 accruals be ultimately denied and rate-making remain on a pay-as-you-go

basis, results of operations and possibly financial condition would be adversely impacted.

Another new FASB standard, SFAS 112, Employers',

Accounting for Post-employment Benefits,.will require, beginning in 1994, the accrual of the cost of benefits provided to former or inactive employees who are'not retired. SFAS 112 is not expected to have a significant effect on financial condition.

10

Independent Auditors'eport Deloitte a Touche 155 East Broad Street Telephone: (614) 221.1000 Columbus. Ohio 43215-3650 Facsimile: (614) 229-4647 INDEPENDENT AUDITORS'EPORT To the Shareowners and Board of Directors ofIndiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets ofIndiana Michigan Power Company and its subsidiaries as ofDecember 31, 1992 and 1991, and the related consolidated statements ofincome, retained earnings, and cash flows for each ofthe three years in the period ended December 31, 1992.

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 fee ofmaterial misstatement.

An audit includes examining, on a test basis, evidence supporting the amounts and disclosuies 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 ofIndiaria Michigan Power Company and its subsidiaries as ofDecember 31, 1992 and 1991, and the results oftheir operations and their cash flows for each of the three years in the period ended December 31, 1992 in conformity with generally accepted accounting principles.

'~~ w/c~~

February 23, 1993

.DeloltteTouche Tohmatsu international

. ~

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES Year Ended December 31, 1992 1991 (in thousands)

$1 195 755

$1,225,667

$1.271,614 OPERATING EXPENSES:

Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization Deferred Operating Costs (net of amortization)

Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses OPERATING INCOME NONOPERATING INCOME (Loss)

INCOME BEFORE INTEREST CHARGES INTEREST CHARGES 193,830 180,365 264,737 172,147 133,365 (30,897) 62,189 25,499 1,001,235 195,520 14,115 209,635 85,687 251,325 122,573 246,935 119,242 132,285 16,961 62,783 46,474 998,578 227,289

~3,721) 223,568 86,636 276,719 162,676 248,806 137,022 131,107 16,961 55,732 41,000 1,070,023 201,491 7,557 209,048 90,657 NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE To COMMON STOCK See Notes to Consolidated Financial Statements.

123,948 15,417 136,932 15,417 118,391 15,587 108,531

$ '21,515 102,804 12

~

Consolidated Balance Sheets ASSETS December 31, 1992 1991 (in thousands)

ELEcTRIc UTILITYPLANT:

Production Transmission Distribution General (includes nuclear fuel).

Construction Work in Progress Total Electric UtilityPlant Accumulated Depreciation and Amortization Net Electric UtilityPlant

$23559,905 829,507 576,309 182,414 115 345 4,266,480 1,631,438 2,635,042

$2,528,229 815,742 551,055 157,340 83,454 4,135,820 1,521,349 2,614,471 OTHER PROPERTY AND INYEsTMENTs 403,111 370,334 CURRENT AssETs:

Cash and Cash Equivalents Accounts Receivable:

Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel at average cost Materials and Supplies at average cost Accrued Utility Revenues Other Total Current Assets 7,459 62,325 41,139 31,536 (562) 53,210 54,004 78,555 11,163 338,829 12,335 64,602 35,894 27,139 (629) 59,148 49,084 37,487 7,953 293,013 DEFERRED CHARGEs 235,482 169,612 Total See Notes to Consolidated Financial Statements. '3,612,464

$3,447,430

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t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES CAPITALIZATIONAND LIABILITIES December 31, 1992 1991 (in thousands)

CAPITALIZATION:

Common Stock No Par Value:

Authorized 2,500,000 Shares Outstanding 1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareowner's Equity Cumulative Preferred Stock Not Subject to Mandatory Redemption Long-term Debt Total Capitalization OTHER NONCUAAENT LIABILITIES CURRENT LIABILITIES:

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

General Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other Total Current Liabilities DEFERRED INCOME TAXES DEFERRED INVESTMENT,TAX CREDITS DEFEARED GAIN ON SALE AND LEASEBACK ROCKPORT PLANT UNIT 2 DEFERAED CREDITS 56,584 726,157 171,309 954,05D 197,000 1,168,721 2,319,771 297,475 42,902 44,20D 37s214 12,471 15,829 22,759 32,745 71,891 280,011 283,543 195,043 218,754 17,867 56,584 726,157 169,243 951,984 197,000 1,112,209 2,261,193 221,749 18,500 50,950 48,211 16,562 11,315 22,788 26,672 64,571 259,569 252,532 205,181 226,965 20,241 C0MMITMENTs AND C0NTINGENGIEs (Note 3)

Total

$3,612,464

$3,447,430 14

Consolidated Statements of Cash Flows 1992 Year Ended December 31, 1991 (in thousands) 1990 OPERATING ACTIvITIEs:

Net Income Adjustments for Noncash Items:

Depreciation and Amortization Deferred Operating Costs (net of amortization)......

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

Accounts Receivable (net)

Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Interest Accrued Other (net)

Net Cash Flows From Operating Activities....

INYEsTING AcTIVITIEs:

Construction Expenditures Proceeds from Sales of Property Net Cash Flows Used For Investing Activities FINANCING ACTIVITIES:

Issuance of Long-term Debt Retirement of Cumulative Prefeired Stock Retirement of Long-term Debt Change in Short-term Debt (net)

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

Cash and Cash Equivalents January 1

Cash and Cash Equivalents December 31 See Notes to. Consolidated financial Statements.

$ 123,948

$ 136,932

$ 118,391 140,763 16,961 (9,145)

(8,444) 141,453 (30,897) 29,897 (9,673) 141,813 16,961 (21,877)

(9,188)

(4,389)

(14,520) 3,816 (15,222) 9,937 871 3,575 25,723 (20,629)

(2,834)

(8,902)

(201,492)

(14,460)

~1,665 P,432) 1,018 (41,068)

(15,088) 4,514 (29)

~16,419) 34,267 (107,986) 6,039

~101,947 248,709 180,224 (122,597) 3,246

~119,351 (125,908) 903 125,005 40,000 (19,048)

(451,770) 36,220 (114,609)

~16.094 78,634 (92,623) 12,055 (102,680)

~15.417 271,722 (203,185)

(6,750)

(106,465)

~16 417)

~525,301) 120,031 60,095 9,327 3,008 (592,981) 595,989 (4,876) 12)335 7,459 12,335 3,008 15

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings 1992 Year Ended December 31, 1991 (in thousands) 1990 Retained Earnings January 1

Net Income

$169,243 123,948 293,191

$150,408 136,932 287,340

$1 62,213 118,391 280,604 Cash Dividends Declared:

Common Stock................

Cumulative Preferred Stock:

4'/e%

Series 4.56%

Series 4.12%

Series 7.08%

Series 7.76%

Series 8.68%

Series 12%

Series

$2.15 Series

$2.25 Series

$2.75 Series Total Dividends

'etained Earnings December 31 See Notes to Consolidated Financial Statements.

106,465 495 273 165 2,124 2,716 2,604 3,440 3,600 121,882

$171,309 102,680 495 273 165 2,124 2,716 2,604 3,440 3,600 118,097

$ 1 69,243 114,609 495 273 165 2,124 2,716 2,604 48 3,440 3,600 122 130,196

$150,408

~

Notes to Consolidated Financial Statements 1 ~ SIgnificant Accounting Policies:

Organization and Regulation Indiana Michigan Power Company (the Company or l&M) is a whollyowned subsidiary of American Electric Power Com-pany, Inc. (AEP), a public utilityholding company. The Com-pany is engaged in the generation,

purchase, transmission and,distribution of electric power and is a member of the AEP System with its facilities operated in conjunction with the facilities of other AEP owned utilities as an integrated utility system. The Company's 4,759 megawatts (mw) of generating capacity comes from two nuclear units, seven coal-fired units, one gas unit and 33 hydro units, some of which are jointly owned with an affiliated company.

The Company is subject to the regulation of the Securities and Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935 (1935 Act). Retail rates are regulated by the Indiana Utility Regulatory Commission (IURC) and the Michigan Public Service Commission (MPSC).

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

The Company has two wholly owned subsidiaries:

Black-hawk Coal Company and Price River Coal Company, which were formerly engaged in coal-mining operations. Blackhawk Coal Company currently leases and subleases portions of its coal rights, land and related mining equipment to unaffiliated companies.

Merger After receiving all applicable regulatory approvals, I&Mand Michigan Power Company (MPCo), a wholly owned subsid-iary of AEP, merged effective February 29, 1992. The merger was accounted for as a pooling-of-interests.

In connection with the merger, the common stock of MPCo was canceled by AEP and the Company did not issue any new common stock. Instead the common equity of MPCo was recorded as additional paid-in capital on the Company's books. The 1992 financial statements reflect the merger as if it had occurred at the beginning of the year. The financial statements for1991 and 1990 have been restated to be comparative.

The separate companies were both using the FERC Uniform System of Accounts and the same fiscal year prior to the merger.

Consequently, no adjustments were made to the Company's net asset balances.

The followingtable shows the separate information for I&M and MPCo for the two months ended February 29, 1992:

I&M MPCo (in thousands)

Operating Revenues..............

$199,018

$7,719 ItetIncome...

24,484 449 17 Reconciliation of revenues and net income for the years ended December 31, 1991 and 1990 for the separate com-panies to the amounts shown herein is as follows:

1991 1990 (in thousands)

Operating Revenues:

I&M MPCo Intercompany Adjustments As shown herein.......

Net income:

l&M MPCo Intercompany Adjustments As shown herein.......

$1,211,607

$1,257,089 46,557 45,655 (32,297)

(31,230)

$1,225,867

$1,271,514 S

135,286 1,646 S

116,315 2,076 S

136,932 S

118.391 Electric UtilityPlant; Depreciation and Amortization; Other Property and Investments Electric utility plant, which is stated at original cost, gen-erally is subject to first mortgage liens.

The Company capitalizes, as a construction cost, an allow-ance for funds used during construction (AFUDC), a non-cash income item, which is defined in the FERC Uniform System of Accounts as the net cost of borrowed funds used for con-struction purposes and a reasonable return on equity funds when so used. The composite AFUDC rates used after com-pounding on a semi-annual basis were 9.25% in 1992 and 1991 and10.5% in1990. AFUDC is recorded on construction expenditures for projects which exceed 30 days in duration.

Since there were no significant tong-term construction proj-ects, AFUDC was not significant in 1992, 1991 and 1990.

Property accounts are charged with the cost of property additions, major replacements of property and betterments.

The accumulated provisions for depreciation are charged with retirements and associated removal costs net of salvage.

Depreciation rates include amounts pertaining to the demo-lition of non-nuclear plant. The accounting and rate-making treatment afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3.

Principles of Consolidation The consolidated financial statements include the accounts of the Company and its whollyowned subsidiaries. Significant intercompany transactions have been eliminated in consolidation.

Basis ofAccounting The financial statements reflect rate-making and contain regulatory assets and liabilities as deferred charges and cred-its in accordance with Statement of Financial Accounting Standards No. 71, Accounting forthe Effects ofCertain Types of Regulation (SFAS 71). The financial statements conform to the accounting and reporting requirements of the SEC under the Securities Exchange Act of 1934. The Company is also subject to the Uniform System of Accounts prescribed by the FERC and the requirements of the state commissions.

I INDIANAMICHIGANPOWER COMPANY AND'SUBSIDIARIES Depreciation is provided for on a straight-line basis over the estimated useful lives of property and determined largely through the use of composite rates by functional class of property.

Other property and investments are stated at cost.

Levelization ofNuclear Refueling Outage Costs Effective January 1, 1992, with the approval of its state regulatory commissions and the FERC, the Company began to defer incremental operation and maintenance costs asso-ciated with refueling outages at the Donald C. Cook Nuclear Plant (Cook Nuclear Plant) for amortization over the period beginning with the commencement of an outage until the beginning of the next outage. In 1992 $71.8 million of incre-mental outage costs were deferred, and $24.6 million amor-tized. The net deferral is included in "Deferred Operating Costs" in the Consolidated Statements of Income.

Jointly-owned and Leased Faci%'tI'es The Company and AEP Generating Company (AEGCo), an affiliate, each own a 50% interest in the 1,300-mw Rockport Plant Unit 1 (Rockpo'rt 1) which went into commercial oper-ation on December 10, 1984, and leases a 50% interest in the 1,300-mw Rockport Plant Unit 2 (Rockport 2) which went into commercial operation on December 1, 1989. The leases are accounted for as operating leases. I8 M operates the plant and bills AEGCo for its share of operating costs. IBM has contractual commitments to buy all ofAEGCo's share of Rock-port energy and to pay a demand charge forthe right to receive such power. The amount of the demand charge is such that when added to other amounts received by AEGCo, it will enable AEGCo to recover all its operating and other expenses including a FERC-approved rate of return on common equity.

At December 31, 1992, l&M's investment in the Rockport Plant was $462 million, net of depreciation.

Cash and Cash Equivalents

Cash, unrestricted special deposits, working funds, and temporary cash investments as defined by the FERC are con-sidered to be cash and cash equivalents.

Temporary cash investments include highly liquid investments purchased with an original maturity of three months or less.

Income Taxes Deferred income taxes are provided except where flow-through accounting for certain timing differences is reflected in rates. The effect of tax reductions resulting from investment tax credits utilized in prior years'ederal income tax returns was deferred and is being amortized over the life of the related plant investment.

Operating Revenues Revenues are accrued for electric service, rendered but unbilled at month-end.

Other Gains or losses on reacquired debt that is refinanced are deferred and amortized over the term of the replacement debt in accordance with rate-'making treatment.

Gains or losses on reacquired, debt that is not refinanced are recognized in income in the year of reacquisition in accordance with reg-ulatory approvais.

Debt discount or premium and debt issuance expenses are being amortized over the lives of the related debt issues, and the amortization thereof is included in interest charges.

The excess of par value over costs of cumulative preferred stock reacquired to meet sinking fund requirements Is credited to paid-in capital. Redemption premiums are deferred and amortized in accordance with rate-making treatment.

Certain prior-period amounts have been reclassified to con-form to current-period presentation.

Fuel Costs Retail jurisdictional fuel costs are billed under fuel recovery mechanisms designed to reflect, in rates, changes in costs of fuel with the approval of state regulatory commissions.

Accordingly, revenues are accrued related to unrecovered fuel and replacement power costs during outages.

Changes in wholesale jurisdictional fuel costs are not deferred.

Instead wholesale fuel costs are generally billed monthly.

18

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

2. Bate Matters:

Rate Recovery In April 1992 testimony and exhibits were filed with the IURC seeking a $44.8 million increase in annual rates to recover increased operating costs. The Office of UtilityCon-sumer Counselor (UCC) recommended in testimony a $30.8 million annual rate decrease.

The IURC concluded hearings and is expected to issue a rate order in 1993. A significant portion of the difference between the request and the UCC's recommended decrease is related to depreciation rates. Ifthe IURC were to adopt the depreciation rates proposed by'the UCC, there would be no immediate effect on earnings but cash flow would be reduced.

Unless the Company receives adequate and timely rate relief, results of operations and pos-sibly financial condition would be negatively impacted.

In June 1992 the FERC issued an order on a November 1989 Initial Decision of a FERC Administrative Law Judge (ALJ) concerning a rate increase for wholesale customers.

In 1987 the Company filed for an increase in wholesale rates of

$3.1 million. Settlements were reached with three of the five wholesale customer classes in 1988 which the FERC approved. As a result of the June 1992 order, the Company refunded $6.3 million including interest to the two remaining wholesale customers in 1993. The Company had previously provided for the refund.

The FERC order denied recovery from the two wholesale customers of certain Rockport 1 phase-in costs and denied the request to shorten the recovery period of the Rockport 1 rate phase-in plan from 30 years to 10 years. The 10 year recovery period was requested in order to comply with State-ment of Financial Accounting Standards No. 92, Regulated Enterprises Accounting for Phase-in Plans (SFAS 92).

Since the FERC-approved phase-in plan for the two wholesale customers does not satisfy the requirements of SFAS 92, $7.2 million of costs associated with the Rockport1 phase-in plan were written off in June 1992. The Company had previously provided for the write-off. Although written off for financial reporting purposes, these costs are expected to be recovered in rates and recognized as revenues over the remaining life of the FERC-approved 30-year phase-in plan.

Unaffiliated Coal and AffiliatedTransportation Cost Recovery A FERC ALJ issued an initial decision in 1990 regarding a complaint filed by a wholesale customer concerning the rea-sonableness of coal costs from an unaffiliated supplier who leased a Utah mining operation from the Company in 1986 and the coal transportation charges of affiliates. The initial decision would have required refunds to wholesale customers of $25 million related to coal costs and an undetermined amount for affiliated transportation charges.

In February1993 the FERC reversed the ALJ's decision and dismissed the complaint.

Rockport 1 Phase-in Plan Under phase-in plans that comply with the requirements of SFAS 92, deferrals made during the first three years of operation of Rockport 1 are being recovered and amortized

'n a straight-line basis through 1997. At December 31, 1992 and 1991, the unamortized deferred returns were $58 million and

$76 million, respectively, and unamortized deferred depreciation were $17 million and $22 million, respectively.

The Company amortized and recovered $16 million in 1992 and $17 million in 1991 and 1990 which are included in "Deferred Operating Costs" in the Consolidated Statements of Income.

Nuclear Unit Outage Cost Recovery Cook Plant Unit 2 experienced an extended, unscheduled, non-nuclear related outage beginning in July 1992 which resulted in additional costs for replacement power. The unit returned to service in December.

Under the fuel recovery mechanism, incremental purchased power costs which, along with other replacement power costs incurred during refueling outages of both nuclear units, resulted in the accrual of unre-covered fuel revenues of $38 million through December 31, 1992.

In Indiana the accrued revenues-are being collected during the first six months of 1993. Recovery in Michigan willbe sought in the next power supply recovery proceeding.

3. Commitments and Contingencies:

Construction Construction expenditures for the years 1993-1995 are estimated at $458 million and, in connection with the con-struction program, commitments have been made.

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

Fuel Supply The Company has long-term contracts to obtain fuel for electric generation.

The contracts generally contain clauses that provide for periodic price adjustments and the fuel clause mechanisms generally provide for recovery of changes in fuel cost. The contracts are forvarious terms, the longest ofwhich extends to the year 2014, and contain clauses that would release the Company from its obligation under certain conditions.

19

. ~

i INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Litigation In November 1992 the DeKalb County Circuit Court of Indi-ana dismissed the case of a local distribution utility against the Company. The case was filed under a provision of Indiana law that allows the local distribution utilityto seek damages equal to the gross revenues received by a utilitythat renders service in the designated service territory of another utility.

The Company had received approximately $29 millionin gross revenues from a major industrial customer in the local dis-tribution utility's service territory.-The case resulted'from a

Supreme Court of Indiana decision which overruled an appeals court and voided an IURC order which assigned the major industrial customer to the Company. The local distribution utility has begun to appeal this case.

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

Environmental Matters Clean Air The Clean Air Act Amendments of 1990 (CAAA) require, among other things, significant reductions in sulfur dioxide and nitrogen oxide emissions from various existing AEP Sys-tem generating plants. The law established a deadline of 1995 for Phase I reductions and 2000 for Phase II reductions as well as a permanent nationwide cap on sulfur dioxide emis-sions after 1999..

The AEP Systemwide compliance plan calls for fuel switch-ing to medium-sulfur coal at Tanners Creek Unit 4 with no additional capital cost. The Breed unit which is a Phase I

affected unit is expected to be retired prior to the January 1, 1995 effective date of the CAAA. The Company's other gen-erating units are not affected in Phase I.

The Company will incur additional costs to comply with Phase II requirements at its generating plants and those of affiliated AEP System Power Pool members.

If unable to recover compliance costs from its customers,.results of oper-ations and financial condition would be adversely impacted.

The United States signed and ratified a United Nations treaty that, when effective, would require the United States to com-mit to a process of achieving the aim of reducing the emission of "greenhouse"

gases, including carbon dioxide. The U.S.

Government released for public comment a draft of the national action plan for achieving this aim, which emphasizes reductions in the use of fossil fuel, the largest source of carbon dioxide, through voluntary energy efficiency programs and some regulatory controls, particularly on the electric util-ity industry. One option for con{rolling carbon dioxide emis-sions is a carbon or energy tax. The Clinton Administration has proposed an energy tax based on the heat content of all fuels including coal. Such new tax could negatively impact the economy of the service area and sales of energy.

The Company intends to seek recovery of all environmental costs incurred in the generation, transmission and distribu-tion of electric energy for the benefit of its customers.

If not recovered from customers, new environmental costs includ-ing any related new taxes would adversely affect results of operations and financial condition.

Nuclear Insurance The Price-Anderson Act limits public liabilityfor a nuclear incident at any nuclear. plant in the United States to $7.8 billion. The Company has insurance coverage for liabilityfrom a nuclear incident at its Cook Nuclear Plant. Such coverage is provided through a combination of private liability insur-ance, with the maximum amount available of $200 million, and mandatory participation, for the remainder of the $7.8 billion liability, in an industry retrospective deferred premium plan which would in case of a nuclear incident assess all licensees of nuclear plants in the United States.

Under the deferred premium plan the Company could be assessed up to $132 million payable in annual installments of $20 million in the event of a nuclear incident at Cook or any plant in the United States.

There is no limit on the number of incidents for which the Company could be assessed.

Other Environmental Matters The Company and its subsidiaries are subject to regulation by federal, state and local authorities with respect to air-and water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.

The generation of electricity produces non-hazardous and hazardous by-products. Also asbestos, polychlorinated biphenyls (PCBs) and other hazardous materials have been used in the generating plants and transmission/distribution facilities. Substantial costs are incurred to store and dispose of hazardous materials in accordance with current laws and regulations. Significant additional costs could be incurred to meet the requirements of new laws and regulations.

20

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

The Company also has property damage, decontamina-tion and decommissioning insurance in the amount of

$2.625 billion. Nuclear insurance pools provide $1.3 bil-lion of coverage and Nuclear Electric Insurance Limited (NEIL) provides the remainder. If NEIL's losses exceed its available resources, the Company would be subject to a retrospective premium assessment of up to $9.9 million. Nuclear Regu-latory, Commission regulations require that the insurance pro-ceeds must be used, first, to return the reactor to, and maintain it in, a safe and stable condition and, second, to decontaminate the reactor and reactor station site. The in-surers then would indemnify the Company for property dam-age up to $2.425 billion less any amounts used for stabilization and decontamination.

As provided by NEIL the remaining $200 million (less any stabilization.and decontam-ination expenditures over $2.425 billion)would cover decom-missioning costs in excess of funds already collected for decommissioning, as discussed below.

NEIL's extra-expense program provides insurance to cover extra costs from a prolonged accidental outage of a nuclear unit. The Company's policy insures against such increased costs up to approximately $3.5 million per week (starting 21 weeks after the outage) for the first year, $2.3 million per week for the second and third years, or 80% of those amounts per unit if both units are down for the same reason. If NEIL's losses exceed its available resources, the Company would be subject to a retrospective premium assessment of up to $9 million.

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including liabilities relating to damage to the Cook Nuclear Plant and'other costs in the event of a nuclear incident at the Cook Nuclear Plant. Future losses or liabilities which are not completely insured, unless recovered through rates, would have a material adverse effect on results of operations and financial condition.

Disposal of Spent Nuclear Fuel The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of spent nuclear fuel and assessed owners of nuclear plants fees for the disposal cost. The Company entered into a contract with the U.S. Department of Energy (DOE) forthe disposal of spent nuclear fuel from its Cook Nuclear Plant. Under the terms of the contract the Company pays a fee of one mill per kwh for fuel consumed after April 6, 1983. The fee is being collected from customers and remitted to the U.S. Treasury. A fee of

$72 million (plus interest of $71 million to December 31, 1992) for disposal of fuel consumed prior to April 7, 1983 has been recorded as other long-term debt and deferred until recovered from customers. The amount deferred ($25.6 mil-lion as of December 31, 1992) is being amortized on a basis commensurate with recovery from customers.

Due to the delays and continuing uncertainties of DOE's program for permanent disposal of spent nuclear fuel, the Company has not commenced paying the fee for fuel consumed prior to April 7, 1983. Funds collected from customers are deposited in external funds until used to pay disposal fees.

Nuclear Decommissioning An independent consulting firm estimated the cost of decommissioning Cook Nuclear Plant at $330 million to $369 million in 1989 dollars. All rate-making jurisdictions have authorized the recovery of an approved level of decommis-sioning costs.

In 1991 the consultant's updated study estimates, based on changed conditions (related to delays in DOE's program for disposal of spent nuclear fuel and other factors), that the cost of post-shutdown fuel storage and decommissioning at the Cook Nuclear Plant would be in the range of $588 million to $1,102 million in 1991 dollars. The substantial increase is due primarily to the possible need to store spent nuclear fuel at the plant site for an extended time after the plant ceases operation delaying the commencement of dismantling activ-ities. Variables in the length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations, which is dependent on future developments in DOE's program for disposal of spent nuclear fuel, have widened the range of the estimate.

The April 1992 Indiana rate increase filing seeks to recover an additional $10 million annually for decommissioning the Cook Nuclear Plant. The Company intends to seek an appro-priate increase in its level of collections for decommissioning expense in its other jurisdictions. The Company willcontinue to periodically reevaluate the cost of decommissioning and to seek increased recovery in rates as necessary.

The Company records decommissioning costs in other operation expense and records a provision for nuclear decom-missioning expense in other noncurrent liabilities in amounts equal to the decommissioning costs recovered from cus-tomers which was $ 12 million in 1992, $11 million in 1991 and $10 million in 1990. Funds recovered through the rate-making process for nuclear decommissioning are deposited in external funds for the future payment of decommissioning

. costs. Trust fund earnings increase the fund balance and the recorded liability, thus reducing the amount to be collected from customers.

Energy Policy Act Nuclear Fees In October 1992 the National Energy Policy Act of,1992 (Energy Act) was signed into law. The Energy'ct contains a provision to fund the decommissioning and decontamination of DOE's existing uranium enrichment facilities from a com-bination of sources including assessments against electric utilities which purchased enrichment services from DOE facil-21

. ~

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES ities. The Company's assessment is estimated to be approx-imately $48 million subject to inflation adjustments and is payable in annual assessments over 15 years. The assess-ment was recorded as a deferred charge concurrent with recording of the liability. The first year estimated assessment

'of $3.25 million will be recognized as a fuel expense,

and, under the provisions of the Energy Act, recovery willbe sought in the next fuel rate adjustment proceedings.

4.'ommon Shareowner's Equity:

Except for the effect of the merger of MPCo discussed in Note 1, there were no transactions affecting the common stock or paid-in capital accounts in 1992, 1991 or 1990.

Covenants in mortgage indentures, debenture and bank loan agreements, charter provisions and orders of regulatory authorities place various restrictions on the use of retained earnings to pay dividends (other than stock dividends) on common stock and for other purposes.

At December 31, 1992, approximately $45.9 million of retained earnings were restricted. In addition, regulatory approval is required to pay dividends out of paid-in capital.

S. Related-party Transactions:

The Company is a member of the AEP System Power Pool (Power Pool) which allows the Company to share the benefits and costs, associated with the System's generating plants.

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

Power Pool members are compensated for the out-of-pocket costs of energy they deliver to the Power Pool by energy credits. Likewise Power Pool members pay energy charges for the energy they receive.

The Company received credits totaling $154.1 million in 1992, $204.8 million in 1991 and $230.5 million in 1990 from providing capacity and supplying energy to the Power Pool and recorded them as operating revenues.

The charges for energy received from the Power Pool were included in purchased power expense and totaled $82.6 million in 1992,

$24.6 million in 1991 and $53.9 million in 1990.

As a Power Pool member the Company shares in wholesale sales to unaffiliated utilities made by the Power Pool. The Company's share was included in operating revenues in the amount of $45.8 million in 1992, $65.5 million in 1991 and

$126.7 million in 1990.

In addition, the Power Pool purchases power for immediate resale to other unaffiliated utilities. The Company's share of these purchases was included in purchased power expense and totaled $6.5 million in 1S92, $13.7 million in 1S91 and

$28.2 million in 1990. Revenues from these transactions are included in the above Power Pool wholesale sales.

The cost of power purchased from AEGCo, an affiliated company that is not a member of the Power Pool, was included in purchased power expense in the amounts of $88 million, $83 million and $79 million in 1992, 1991 and 1990, respectively.

The Company participates with other AEP System com-panies in a transmission equalization agreement. This agree-.

ment combines certain AEP System companies'nvestments in transmission facilities and shares the costs of ownership in proportion to the System companies'espective peak demands.

Pursuant to the terms of the agreement, credits of

$48.2 million, $46.2 million and $47.6 millionwere recorded in other operation expense for transmission services in 1992, 1991 and 1990, respectively.

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

Year Ended December 31 ~

1992 1991 1990 (in thousands)

$24,753

$23,863

$25,851 3,964 4,641 2,882

$28,717

$28,504

$28,733 Affiliated Companies...

Unaffiliated Companies Total American Electric Power Service Corporation (AEPSC) pro-vides certain management and professional services to AEP System companies.

The costs of the services are determined by AEPSC on a direct-charge basis to the extent practicable and on reasonable bases of proration for indirect costs. The charges for services are made at cost and include no com-pensation forthe use of equity capital, all ofwhich is furnished to AEPSC by AEP. The Company expenses or capitalizes bill-ings from AEPSC depending on the nature of the service rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.

6. Benefit Plans:

The Company and its subsidiaries participate with other companies in the AEP System in a trusteed, noncontributory defined benefit plan to provide pensions, subject to certain eligibility requirements, for all employees.

Plan benefits are determined by a formula which considers each participant's highest average

earnings, years of accredited service and social security covered compensation.

Pension costs are allo-cated to each System company by first charging each System company with its service cost and then allocating the remain-ing pension cost in proportion to its share of the projected 22

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued) benefit obligation. The funding policy is to make annual con-.

tributions to the plan's trust fund in an amount equal to the net periodic pension cost to the extent deductible for federal income tax purposes, but not less than the minimum contri-bution required by law.

Net pension costs for the years ended December 31, 1992, 1991 and 1990 were $5.6 million, $2.3 million and $2.8 million, respectively.

In addition to pension benefits, certain other benefits are provided to. retired employees under an AEP System other post-retirement benefit plan. Employees become eligible for health care and life insurance benefits if they have 10 years of service at retirement. The cost of such retiree benefits is recognized as an expense when paid and.totaled $2.7 million in 1992, $2.6 million in 1991,and $2.8 million in 1990.

The AEP System's pension and other post-retirement ben-efit plans were amended effective January 1, 1992.

The change in the pension plan allows employees to retire without reduction of benefits at age 62 instead of age 65 and to retire as early as age 55 instead of age 60 with reduced benefits.

The change in the other post-retirement benefit plan grants employees eligibilityfor health care and life insurance benefits if they retire as early as age 55 with 10 years of service.

Previously employees could not receive other post-retirement benefits unless they retired at age 60 or later.

The Company offers an AEP System employee savings plan under which eligible participants can invest from 1% to 16%

of their salaries among three investment alternatives, includ-ing AEP common stock. An employer contribution equal to one-half. of the first 6% of the employees'ontributions is invested in AEP common stock. The annual contributions to the savings plan trust were $3.3 million in 1992, $3.1 million in 1991 and $2.9 million in 1990.

The Financial Accounting Standards Board (FASB) has issued Statement of Financial Accounting Standards No. 106, Fmployers'ccounting for Postretirement Beneff'ts Other Than Pensions (SFAS 106) which requires employers, begin-ning in 1993, to accrue for the costs of retiree benefits other than pensions.

In addition to accruing the current cost, SFAS 106 also requires the recognition of an employer's prior selv-ice costs (the unfunded and unrecognized accumulated'post-retirement benefit obligation) in the initial year of implemen-tation or as a transition obligation over either the greater of the average remaining service period of employees or 20 years. The Company adopted SFAS 106 in January 1993 and elected the 20-year transition option.

In anticipation of the new accounting requirement, the Company undertook several measures to reduce the impact of adopting the new standard. First, the Company established a Voluntary Employee Beneficiary Association (VEBA) trust fund for post-retirement benefits other than pensions and made a $4.3 million contribution in 1990, the maximum amount deductible for federal income tax purposes. Another-Real and Personal Property...

State Gross Receipts, Excise, Franchise and Miscellaneous State and Local State Income Payroll Total 1992

$35,818 15,179 2,281 8,911

$62,189 1991 (in thousands)

$33,265 15,902 5,541 8,075

$62.783 1990

$27,913 13,455 6,607 7,757

$55,732 The following are the amounts of cash paid for:

Year Ended Oecember 31 ~

1992 1991 1990 (in thousands)

Interest (net of capitalized amounts)

Income Taxes......"..

$84,581

$103,407 73,694 248,338

$84,691 15,285 The amounts of non-cash acquisitions under capital leases were $47,905,000 in 1992, $25,624,000 in 1991 and

$57,227,000 in 1990.

measure taken in 1990, except where restricted by state law, was to implement a program ofcorporate owned lifeinsurance to help fund and reduce the future cost of post-retirement benefits other than pensions.

The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, as other property and invest-ments. The policies generated cash of $1.7 million in 1992 and $700,000 in 1991 inclusive of related tax benefits which was contributed to the VEBA trust fund.

The annual accrued expense required by SFAS 106 for employees and retirees, inclusive of the cost of the changes in the other post-retirement benefit plan and 20-year recor-dation of an $83 million transition obligation, is expected to be $ 1 2.3 million in 1993 versus $4.4 million on the prior pay-as-you-go method. The Company has received authority from the FERC to defer, beginning January 1, 1993, under the provisions of SFAS 71, the increased post-retirement benefit cost which will not be currently recovered in rates after SFAS 106 is implemented. In its Michigan jurisdiction, the Company may defer the SFAS 106 increase in costs for up to three years

'ending recovery in the next base rate case filing. In the Indiana jurisdiction, the Company has filed for full recovery and expects a decision in 1993. Should recovery of the SFAS 106 accruals and related deferrals be denied, results of oper-ations and possibly financial condition would be adversely impacted.

7. Supplementary Information:

The following are the components of taxes other than fed-eral income taxes:

Year Ended December 31, 23

f INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

8. Federal Income Taxes:

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

1992 Year Ended December 31, 1991 (In thousands) 1990 Charged (Credited) to Operating Expenses (net):

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

Current Deferred Deferred Investment Tax Credits Total Total Federal Income Taxes as Reported S 9,122 25,405 (9,028) 25,499 S 73,702

$53,788 (6,871)

(5,917) 41,000 (18,793)

(8.435) 46.474

$118,391 43,855

$162.246 Net Income Federal Income Taxes Pre-tax Book Income 1,569 3,348 7,656 4,492 (3,084)

(2,274)

(645)

(753)

(2,527)

C 5,416 (489) 2,855

$30.915 S 45,985

$43,855 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, 1992 1991 1990 (in thousands)

$136,932 45,985

$182.917 Federal Income Taxes on Pre-Tax Book Income at Statutory Rate (34%)

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

Removal Costs Mine Development and Mineral Rights Amortization Investment Tax Credits (net)

Corporate Owned Life Insurance Other Total Federal Income Taxes as Reported Effective Federal Income Tax Rate The following are the principal components of federal income taxes as reported:

S 52,653 (3,042) 2,129 (9,011)

(4,402)

(7,412)

S 30,915 20.0%

S 62,192 (2,259) 2,773 (9,087)

(3,044)

(4,590)

S 45,985 25.1%

S 55,164 (1,663) 4,369 (11,004)

(1,802)

(1,209)

S 43,855 27.0%

Current:

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

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

Deferred Net Gain Rockport Plant Unit 2 Deferred Nuclear Refueling Costs Accrued Interest Income Other Total Deferred Federal Income Taxes Total Deferred Investment Tax Credits Total Federal Income Taxes as Reported 1992

$10,029 662 10,691 (8,356) 11,729 5,410 (430)

(2,772) 4,230 16,048 3,854 184 29,897 (9,673)

$30,915 Year Ended December 31, 1991 (in thousands)

$76,949 101 77,050 (6,969)

(670)

(6,484)

(2,864) 3,098 (7,988)

(21,877)

(9.188)

$45.985

, 1990

$64,004 (2,560) 61,444 1,135 4,135 384 (3,878)

(2,864) 3,457 (11,514)

(9,145)

(8,444)

$43,855 24

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

The Company and its subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses and investment tax credits utilized to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP, is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approx-imates a separate return result for each company in the con-solidated group.

The AEP System reached a settlement with the Internal Revenue Service (IRS) for 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 being audited by the IRS. In the opinion of management, the final settlement of open years will not have a material effect on earnings.

SFAS

109, Accounting for Income

Taxes, prescribes, among other things, that the Company change from the defer-ral to the liabilitymethod of accounting for income taxes. The Company adopted SFAS 109 effective January 1, 1993. The adoption of the new standard resulted in an increase in net deferred tax liabilities of approximately $259.6 million to reflect temporary differences previously flowed-through and to adjust existing deferred taxes to the level required at the current statutory tax rate. A net regulatory asset of $254.3 millionrelated to the portion of these additional deferred taxes which are recoverable in rates was also recorded with imple-mentation of SFAS109. The implementation of the new stand-ard did not significantly impact results of operations.

As permitted by SFAS 109, the effects of the implementation of the new standard in January 1993 are not reflected in these financial statements.

Operating Leases...........

Capital Leases:

Amortization of Principal.....

Interest Total Rental Payments 1992 1991 1990 (in thousands)

$109,466

$101,013

$ 87,505 24 ~ 124 54,528 46,933 7,473 9,907 10,919

$141,063

$165,448

$145,357

9. Leases:

The Company and its subsidiaries lease property, plant and equipment for periods up to 35 years.

Most of the leases require the payment of related property taxes, maintenance costs and other costs of operation.

The Company and its subsidiaries expect that leases generally will be renewed or replaced by other leases.

The majority of the leases have purchase or'renewal options.

The Company and AEGCo each lease 50% of Rockport 2 which cost $1.3 billion and began commercial operation in December 1989. Rockport 2 was sold in December 1989 for

$1.7 billion, its estimated fair market value, and leased back for an initial term of 33 years. The gain from the sale was deferred and is being amortized, with related deferred taxes, over the initial lease term. The leases are accounted for as operating leases.

The Company leases its nuclear fuel from a special purpose entity which provides for leasing of up to $140 million of nuclear fuel. The special purpose entity owns and finances all of its investment in nuclear fuel. The nuclear fuel lease is accounted for as a capital lease.

Rental payments for'capital and operating leases are pri-marily charged to operating expenses in accordance with rate-making treatment.

The rental payments by lease type and component are as follows:

Year Ended December 31, 25

. ~

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Properties under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:

December 31.

1992 1991 (in thousands)

Electric UtilityPlant:

Production Distribution General:

Nuclear Fuel (net of amortization)....

Other Total Electric UtilityPlant........

Accumulated Amortization Net Electric Utility Plant Other Property Accumulated Amortization Net Other Property.............

Net Properties under Capital Leases Obligations under'Capital Leases (a)

$ 11,407

$ 10,568 14,702 14,661 84,208 46,494 156,811 30,630 126,181 2,327 1,819 508

$126,689

$126,689 66,456 39,242 130,927 28,146 102,781 1,957 1,753 204

$102,985

$102,985 (a) Including amounts due within one year.

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

Future minimum lease payments at December 31, 1992, by year and in the aggregate, are as follows:

Capital Operating Leases Leases (in thousands) 8,243 99,024 7,128 98,667 6,266 98,191 5,556 97,871 5,021 96,014 33,383 2.102,807 1993 1994 1995 1996 1997 Later Years Total Future Minimum Lease Payments 65,597

$2.592,574 Less Estimated Interest Element..

Estimated Present Value of Future Minimum Lease Payments Unamortized Nuclear Fuel Total 23,116 42,481 84,208(a)

$126.689 (a) Including portion due within one yea'r. Rental payments for nuclear fuel willbe paid in proportion to heat produced and carrying charges on the lessor's unrecovered costs.

Nuclear fuel rentals of $23.0 million, $56.6 million and

$50 millionwere charged to fuel expense in 1992, 1991 and 1990, respectively.

Included in the above analysis of future minimum lease payments and of properties under capital leases and related obligations are certain leases in which portions of the related rentals are paid for or reimbursed by affiliated companies in the AEP System based on their usage of the leased property.

The Company and its subsidiaries cannot predict the extent to which affiliated companies will utilize the properties under such leases in the future.

10. Cumulativ'e Preferred Stock:

At December 31, 1992, authorized shares of cumulative preferred stock were as follows:

Par Value Shares Authorized

$100 2,250,000 25 11,200,000 In 1990, the Company redeemed 47,325 shares of the 12'lo series and 531,900 shares. of the $2.75 series cumulative preferred stock subject to mandatory redemption. The cumulative preferred stock outstanding at December 31, 1992 is not subject to mandatory redemption and is callable at the Company's option 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 300,000 shares of 67/eh Cumulative Preferred StockSubject to Mandatory Redemption, par value $100, on February 17, 1993. The cumulative preferred stock not subject to mandatory redemption is as follows:

Series 4'!oo/o 4 56'/0

~ 4.12o/o 7 08'/o 7.76o/o 8.68'/o

$2.15

$2.25" Call Price December 31 ~

1992

$106.125 102 102.728 101.85 102.28 103.10 25.54 26.13 Par Value

$100 100 100 100 100 100 25 25 Shares Outstanding December 31, 1992 120,000 60,000 40,000 300,000 350,000 300,000 1,600,000 1,600,000 Amount December 31 ~

1992 1991 (in thousands)

$ 12,000

$ 12,000 6,000 6,000 4,000 4,000 30,000 30,000 35,000 35,000 30,000 30,000 40,000 40,000 40.000 40.000

$197,000

$197,000 "Called for redemption on March 1 ~ 1993 26

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Concluded)

First Mortgage Bonds.......

Sinking Fund Debentures Notes Payable to Banks Installment Purchase Contracts Other Long-term Debt (a)....

Less Portion Oue Within One Year Total 1992 1991 (in thousands)

S 713,916 S

627,494 6,053 6,053 40,000 S0,000 308,333 308,971 143,321 138,191 1,211,623 1,130,709 42,902 18,500

$1,168.721

$ 1 ~112,209 (a) Nuclear Fuel Disposal Costs Including interest accrued. See Note 3.

First mortgage bonds outstanding were as follows:

December 31, 1992 1991 (in thousands)

% Rate Due 4i/4 1993 August 1....

7r/4 1997 February 1...

9i/4 1997 July 1 7

1998 May 1 7.3 1999 December 15 (a) er/4 2000 April 1.....

7.6 2002 November 1..

7.7 2002 December 15 (a)

-9i/i 2003 tune 1

83/4 2003 December 1..

9'008 March 1....

84/4 2017 February 1...

9.5 2021 May 1 9.5 2021 May 1 9.5 2021 May 1 8.75 2022 May 1 8.S 2022 December 15 (a)

Unamortized Discount (net).....

S 42,902

$ 42,902 50,000 50,000 75,000 75,000 35,000 35,000 35,000 50,000 50,000 50,000 40,000 162,000 40,000 40,000 34,034 34,034 100,000 100,000 10,000 10,0M 10,000 10,000 20,000 20,000 50,000 75,000 (3,020)

(1,442) 713,916 627,494 42,902 13,500

$671,014

$613,994 (a) Proceeds were deposited with a trustee for the January 1993 retirement, prior to maturity, of the 9k% Series due 2003 at the redemption price of 103.718%.

The indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions.

The sinking fund debentures are due May 1, 1998 at an interest rate of 7'/4%. Prior to December 31, 1992, sufficient principal amounts of debentures had been reacquired in antic-ipation of all future sinking fund requirements.

Additional debentures of up to $300,000 may be called annually.

11. Long-term Debt and Lines of Credit:

Long-term debt by major category was outstanding as follows:

December 31 ~

Unsecured promissory notes payable to banks have been entered into as follows:

December 31 ~

1992 1991 (in thousands) 11.8% due 1992................

S-S 5,000 9.07% due 1995................

40,000 40,000 Variable interest rate note due 1996....

5,000 40,000 50,000 Less Portion Oue Within One Year.....

5.000 Total

$40,000

$45,000 The variable interest rate note payable was issued initially bearing interest at the prime rate and due Ja)tuafy1996. This note was retired during 1992. The interest rate on the note was 6.4% at December 31, 1991.

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

December 31, 1992 1991 (in thousands)

% Rate Oue City of Lawrenceburg, Indiana:

8'/4 2006 July 1

7 2006 May 1 6r/4 2006 May 1 7

2015 April 1 City of Rockport, Indiana:

9i/4 2014 August 1..

P/4 (a) 2014 August 1..

(b) 2014 August 1..

7.6 2016 March 1..

City of Sullivan, Indiana:

74/4 2004 May 1 6r/4 2006 May 1 7i/z 2009 May 1 Unamortized Discount Total S 25,000 40,000 12,000 s

40,000 12,000 25,000 50,000 50,000 50,000 40,000 50,000 50,000 50,000 40,000 7,000 7,000 25,000 25,000 13,000 13,000 (3.667)

(3,029)

$308,333

$308,971 (a) The adjustable interest rate changed on August 1 ~ 1990 and will change every five years thereafter.

(b) The variable interest rate is determined weekly. The average weighted Interest was 3.7% for 1992 and 4.7% for 1991.

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

On certain series the principal is payable at stated maturities or on the demand of the bondholders at periodic interest adjust-ment dates. Accordingly, the installment purchase contracts have been classified for repayment purposes based on their next interest rate adjustment date.

Certain series are sup-ported by bank letters of credit which expire in 1995.

27

. ~

INDIANAMICHIGANPOWER COMPANY t

AND SUBSIDIARIES At December 31, 1992, annual long-term debt payments, excluding premium or discount, are as follows:

Principal Amount (in thousands) 1993 42,902 1994 1995 140,000 1996 1997 125,000 Later Years 910,408 Total

$1,218,310 The amount of short-term debt the Company may borrow is limited by the provisions of the 1935 Act to $200 million and further limited by provision of the charter to $141 million.

The Company shares bank lines of credit with other AfP System companies and at December 31, 1992 and 1991 had unused shared lines of $521 millionand $374 million, respec-tively. Under the terms of the lines of credit, notes can be issued with a maturity of up to 270 days. In accordance with agreements with the banks, commitment fees averaging approximately a/te of 1/o a year are required to maintain the lines of credit. Outstanding short-term debt consisted of

$44.2 millionof commercial paper at December 31, 1992 and

$14.9 million of notes payable and $36.1 million of com-mercial paper at December 31, 1991.

12. Disclosures about Fair Value of Financial Instruments The estimated fair value of financial instruments has been determined using available market information and appropri-ate valuation methodologies.

However, considerable judg-ment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates are not necessarily indicative of the amounts that could be realized in a current market exchange. The fair values do not include early redemption premiums, underwriters'ees and commis-sions and refunding costs (legal and registration fees). Also, the Company may be prohibited from realizing the estimated fair values due to noncallable provisions.

The fair value estimates are based on pertinent information as of December 31, 1992. Such amounts have not been com-prehensively revalued for purposes of these financial state-ments since December 31, 1992, and estimates of fair value at any subsequent date may differsignificantly although man-agement is not aware of any factors that would significantly affect the estimated fair value amounts.

The carrying'amount of cash and cash equivalents, accounts receivable, short-term debt and accounts payable shown in the Consolidated Balance Sheet approximates fair value because of the short-term maturities of these instruments.

13. Unaudited Quarterly Financial Information:

The following consolidated quarterly financial information is unaudited but, in the opinion of management, includes all adjustments (consisting of only normal recurring accruals) necessary for a fair presentation of the amounts shown:

Quarterly Periods Operating Operating Net Ended Revenues Income Income (in thousands) 1992 March 31...........

$301,134

$54,022 June 30............

280,421 43,535 September 30.........

311,080 45,323 December 31.........

304,120 52,640 1991 March 31...........

308,149 61,230 40,366 June 30............

292,979 49,295 28,977 September 30.........

314,881 61,493 35,772 December 31.........

309,858 55,271 31,817 Fourth quarter 1992 earnings include $13 million comprised of interest on prior years federal income tax refunds and cost reductions due to favorable benefit plan experience.

$35,035 24,844 24,384 39,685 External trust funds established to accumulate funds col-lected from customers for future nuclear liabilities discussed in Note 3 are included in Other Property and Investments at original cost. The trust funds are invested primarily in long-term tax-exempt municipal bonds. The fairvalue of the instru-ments held in the trust funds approximates carrying value based on estimated market prices for those and similar investments.

Long-term debt is comprised of first mortgage

bonds, notes payable to banks, installment purchase contracts, sink-ing fund debentures and miscellaneous long-term debt instru-ments. The fair value of long-term debt approximates carrying value based on quoted market prices for the same or similar issues and the current interest rates offered for debt of the same remaining maturities.

28

Operating Statistics 1992 1991 1990 1989 1988 OPERATING REYENUEs (in thousands):

Retail:

Residential:

Without Electric Heating................

With Electric Heating Total Residential Commercial industrial Miscellaneous Total Retail Wholesale (sales for resale).................

Total Revenues from Energy Sales......

Provision for Refunds of Revenues. Collected in Prior Years Total Net of Provision for Refunds Other Total Operating Revenues 209,682 98,553 206,257 93,289 192,822 195,504 88,718 95,987 202,390 98,784 308,235 228,285 267,643 11,012 815,175 369,379 299,546 216,303 241,858 12,120 769,827 436,083 281,540 205,025 244,773 11,799 743,137 518,080 291,491 205,918 251,279 12,021 760,709 361,962 301,174 204,229 250,877 12,180 768,460 289,066 1,184,554 1,205,910 1,261,217 1,122,671 1,057,526 4,038 5,176 5,176 1,133 1,211,086 14,781 1,180,516 16,239 1,256,041 15,473 1,122,671 12,916 1,056,393 10,266

$1,196,755

$1,225,867

$1,271,514

$1,135,587

$1,066,659 SOURCES ANO SALES OF ENERGY (in millions of kilowatt-hours):

Sources:

Net Generated:

Fossil Fuel Nuclear Fuel Hydroelectric Total Net Generated......

Purchased and Power Pool......

Total Sources

. Less: Losses, Company Use, Etc..

Net Sources Sales:

Retail:

Residential:

Without Electric Heating With Electric Heating...

Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)..

Total Sales 11,597 6,418 100 18,115 9,342 27)457 1,466 25,991 3,001 1,633 4,634 3,747 5,685 194 14,260 11,731

~25 991 12,109 15,524 109 27,742 5,237 32,979 1,454 31,525 3,166 1,625 4,791 3,726 5,382 233 14,132 17,393 31,525 14,451 11,115 127 25,693 7,983 33,676 1,633 32,043 2,955 1,525 4,480 3,536 5,452 229 13,697 18,346 32,043 10,634 12,094 108 22,836 7,630 30,466 1,647 28,819 2,975 1,627 4,602 3,519 5,512 236 13,869 14,950 28,819 8,707 9,791 82 18,580 6,341 24,921 1,674 23,247 3,005 1,611 4,616 3,431 5,371 236 13,654 9,593 23,247 29

. ~

INDIANAMICHIGANPOWER COMPANY t

AND SUBSIDIARIES OPERATING STATISTICS (Concluded)

AvaeoE CosT oF FUEL CoNsuMEo (in cents):

Per Million Btu:

Coal Nuclear Overall Per Kilowatt-hour Generated:

Coal Nuclear Overall 1992 136 54 103 1.34

.61 1.08 1991 141 48 84 1.39

.53

.91 1990 145 58 105 1.42

.64 1.08 1989 164 61 106 1.62

.67 1.11 1988 182 70 120 1.81

.77 1.26 RESIDENTIAL SERVICE AVERAGES:

Annual Kwh Use per Customer:

Total With Electric Heating Annual Electric Bill:

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

Total With Electric Heating NUMBER OF CUSTOMERS:

Year-End:

Retail:

Residential:

Without Electric Heating With Electric Heating...

Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)..

Total Customers 10,107 17,513

$672.31

$1,056.91 6.65 6.04 366,835 94,175 461,010 52,542 5,000 1,751 520,303 53 520,356 10,539 17,703

$659.01

$1,016.24 6.25 5.74 364,154 92,657 456,811 51,491 4,847 2,226 51 5,375 53 515,428 9,944 16,897

$624.95

$983.28 6.28 5.82 362,645 91,179 453,824 50,994

, 4,801 2,160 511,779 55 511,834 10,303 18,337

$652.64

$1,081.78 6.33 5.90 360,040 89,881 449,921 50,043 4,792 2,168 506,924 51 506,975 10,449 18,438

$681.72

$1,130.71 6.52 6.13 356,755 88,366 445,121 48,958 4,766 2.123 500,968

'09 501,077 30

Dividends and Price Ranges of Cumulative Preferred Stock By Quarters (1992 and 1991)

Cumulative Preferred Stock 1st 1992 Quarters 2nd 3rd 4th 1st 1991 Quarters 2nd 3rd 4th

($100 Par Value) 4/s% Series Dividends Paid Per Share Market Price $ Per Share (MSE) High Low 4.56% Series Dividends Paid Per Share Market Price $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 4.12% Series Dividends Paid Per Share Market Price S Per Share (OTC)

Ask (high/low).

Bid (high/low) 7.08% Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low 7.76% Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low 8.68% Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low

($25 Par Value)

$2.15 Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low

$2.25 Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low

$1.03

$1.03

$1.03

$1.03

$1.03

$1.03

$1.03

$1.03 47/391/2 47/47 48/47 50/48

$1.77

$1.77

$1.77

$1.77 42/39'/a 42/39'/a 42'/439M 44/39'/a

$1.77

$1.77

$1.77

$1.77 88'/

83'/

88'/a-84'/a 92 85'/z 92 89 80'/s 71 79'/4 76'/4 83 76'/4 85'/s 81

$ 1.94

$1.94

$1.94

$1.94 95'/4 90'/a 96'/s 92'/4 98'/s 93'/a 981/4 93

$1.94 92 83

$1.94 87s/s 83'/s

$1.94

$1.94 87 83'/s 92s/4 88

$2.17

$2.17

$2.17

$2.17

$2.17

$2.17

$2.17

$2.17 102'/4 98'/z 102

.99 103 100'/s 103 100 94s/s 89 95 92'/z 96'/a 91'/z 100'/z 95

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375 26 25 26 25 27'/4 25s/s 27 25'/a 25 23'/s 25'/s 231/2

. 25s/s 23'/a 26 24'/a

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625 27'/4 26 27'/s 25'/s 27'6 27'/4 25'/4 26 23'/s 25%

24M 26 24'/4 26'li 24

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125 39 36 39 36

$1.14

$1.14

$1.14

$1.14

$1.14

$1.14

$1.14

$1.14 MSE Midwest Stock Exchange OTC Over. the. Counter NYSE Nsw York Stock Exchange Note The above bid and asked quotations represent prices between dealers and do not represent actual transactions.

Market quotations provided by National Quotation Bureau, Inc.

'ash indicates quotation not available.

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 Company's Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1993 to shareowners and at no cost. 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 30 West Broadway New York, NY 10007 32

Indiana Michigan Power Service Area and the American Electric Power System Leke Nl oh lien MICHIGAN OHIO INDIANA WEST VIRGINIA KENTUCKY VIRGINIA LEGEND Indiana Michigan U Power Co. Area D

Other AEP operating companies'reas 0

Major power plant TENNESSEE M printed on recycled paper

ENCLOSURE 2 TO AEP:NRC:0909I INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW

~ tees Internal Cash Flow ProJectlon for Donald C. Cook Nuclear Plant

($ Millions)

Actual 1992 Projected 1993 Net Income AfterTaxes Less Dividends Paid Retained Earnings 123.9 121.9 2.0 109.4 119.1 (9 7)

Adjustments:

Depreciation And Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Total Adjustments 157.8 (47.2) 20.2 (3.8) 127.0 154.6 32.8 (48.5)

(2.4) 136.5 Internal Cash Flow Average Quarterly Cash Flow 129.0 32.3 126.8 31.7 Average Cash Balances and Short-Term Investments 7.6 10.2 Total 39.9 41.9

% Ownership In all operating nuclear units:

Unit 1 and Unit 2 - 100%

Maximum Total Contingent Liability- $20.0 million (2 units)

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