ML17334B362

Forwards 1989 Annual Rept & Projected Cash Flow

ML17334B362
Person / Time
Site:	Cook
Issue date:	04/06/1990
From:	Alexich M INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909F, AEP:NRC:909F, NUDOCS 9004180384
Download: ML17334B362 (39)

Text

ACCELERATED D UTION DEMON TION SYSTEM l

REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9004180384 DOC.DATE: 90/04/06 NOTARIZED: NO DOCKET'g FACIL:50-315 Donald C.

Cook Nuclear Power Plant, Unit 1, Indiana S

05000315 50-316 Donald C.

Cook Nuclear Power Plant, Unit 2, Indiana'.6 05000316 AUTH.NAME AUTHOR AFFILIATION ALEXICH,M.P.

Indiana Michigan Power Co.

(formerly Indiana 6 Michigan Ele RECIP.NAME RECIPIENT AFFILIATION R

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SUBJECT:

Forwards "1989 Annual Rept"

& projected cash flow.

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U TITLE: 50.71(b)

Annual Financial Report S

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Indiana Michigan Power Company P.O. Box 'I663I Columbus, OH 43216 AEP:NRC:0909F 10 CFR 50.71(b)

& 140.21(e)

Donald C.

Cook Nuclear Plant Unit Nos.

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 Apri1 6, 1990

Dear Dr. Murley:

Enclosure 1 contains the Indiana Michigan Power Company's (I&M) annual report for 1989.

Enclosure 2 contains a copy of I&M's projected cash flow for 1990.

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

This document has been prepared following Corporate procedures that incorporate a reasonable set of controls to ensure its accuracy and completeness prior to signature by the undersigned.

Sincerely, M. P.

A exich Vice President ldp Enclosures cc:

D. H. Williams, Jr.

A. A. Blind - Bridgman R.

C. Callen G. Charnoff A. B. Davis - Region III NRC Resident Inspector

- Bridgman NFEM Section Chief 9004180384 900406 PDR ADOCK 050003l5 I

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1989, Annual Report (NOD NA MICHIGAN PQWKR Docket ¹ Accession ¹ tc w9/8~ p ~~

Date 6 P'~

of Ltr Regulatory Docket File Indiana Michigan power Company

~IANAMICHIGANPOWER COMPANY One Summit Square,~ Box 60, Fort Wayne, Indiana 46801 Contents

Background

of the Company Directors and Officers of the Company Selected Consolidated Financial Data Management's Discussion and Analysis of Results of Operations and Financial Condition Consolidated Statements of Income Consolidated Balance Sheets

.Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Notes to Consolidated Financial Statements Independent Auditors'eport Operating Statistics Dividends and Price Ranges of Cumulative Preferred Stock 5-8 10-11 12 13 14-24 25 26-27 28

Background of the Company INDIANAMIGHIGAN PowER C0MPANY (the Company), a subsidiary of American Electric Power Company, Inc.

(AEP), is engaged in the generation, purchase, transmission and distribution 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.

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.

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

The Company serves approximately 475,000 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, rubber and plastic products, and electrical and electronic machinery.

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

The Company's generating plants and important load centers are interconnected by a high-voltage trans-mission 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, Michigan Power Company, Ohio Power Company and Wheeling Power Company.

The Company is also interconnected with the following other utilities: Central illinois Public Service Company, The Cincinnati Gas 8 Electric Company, Commonwealth Edison Company, Consumers Power Company, Illinois Power Company, Indiana-Kentucky Electric Corporation (a subsidiary of Ohio Valley Electric Corporation), Indianapolis Power

& Light Company, Northern Indiana Public Service Company, Public Service Company of Indiana, Inc. and Richmond Power 8 Light Company.

'ANAMICHIGANPOWER COMPANY AND SUBSIDIARIES girectors MARKA. BAILEY (a)

W. A. BLACK (b)

RICHARD E. DISBROW WILLIAMN. 0'ONOFRIO A. R. GLASSBURN (C)

M. R. HARRELL (d)

WILLIAMJ. LHOTA (a)

GERALD P. MALONEY RICHARD C. MENGE R. E. PRATER JOSEPH H. VIPPERMAN (b)

W. E. WALTERS W. S. WHITE, JR.

DAVID H. WILLIAMS,JR.

Officers W. S. WHITE, JR.

Chairman of the Board and Chief Executive Officer W. A. BLACK (b)

President and Chief Operating Officer RICHARD C. MENGE (a)

President and Chief Operating Officer MILTON P. ALEXICH Vice President MARKA. BAILEY (e)

Vice President RICHARD E. DISBROW Vice President WILLIAMN. D'ONOFRIO Vice President A. JOSEPH DOWD Vice President RICHARD F. HERING Vice President WILLIAMJ. LHOTA (a)

Vice President GERALD P. MALONEY Vice President JOSEPH H. VIPPERMAN (b)

Vice President DAViD H. WiLLIAMS,JR.

Vice President PETER J. DEMARIA Treasurer 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, 1990 the principal occupation of the current directors and officers of Indiana Michigan Power Company, with eight exceptions, is as an employee ofAmerican Electric Power Service Corporation.

The exceptions are Messrs.

Bafile, Bailey, D'Onofrio, Harrell, Menge, Moos, Prater, and Walters, whose principal occupations are as officers or employees of Indiana Michigan Power Company.

(a) Elected October 1, 1989 (b) Resigned October 1, 1989 (c) Resigned April 25, 1989 (d) Elected April 25, 1989 (e) Elected September 1, 1989

Selected Consolidated Financial Data Year Ended December 31, 1989 1988 1987 (in thousands) 1986 1985 INCOME STATEMENTS DATA:

OPERATING REVENUES ELECTRIC.......

OPERATING EXPENSES OPERATING INCOME NONOPERATING INCOME.

INCOME BEFORE INTEREST CHARGES.......

INTEREST CHARGES NET INCOME PREFERRED STocK DIYIDEND REQUIREMENTs EARNINGS APPLICABLE To COMMON STOCK

$1,005,638 795,242

$983,066

$1,017,268

$1,091,295

$1,078,793 767,623 794,222 900,151 886,904 210,396 32 830 215,443 43,454 191,889 76,879 191,144 66,905 258,049 105,568 223,046 56,828 279,874 113,508 166,366 20,955 268,768 122,667

, 258,897 107,092 151,805 18,848 243,326 106,181 152,481 26,256 146,101 27,056 137,145 18,048 119,097

$132,957 145,411 126,225 l19,045 1989 1988 December 31, 1987 (in thousands) 1986 1985 BALANCESHEETS DATA'LECTRIC UTILITY PLANT ACCUMULATED PROVISIONS FOR DEPRECIATION AND AMORTIZATION NET ELECTRIC UTILITY PLANT TOTAL ASSETS COMMON STOCK AND PAID-IN CAPITAL.......

RETAINED EARNINGS TOTAL COMMON SHAREOWNER S EOUITY......

CUMULATIVEPREFERRED STOCK:

NOT SUBJECT To MANDATORY REDEMPTION SUBJECT To MANDAT0RY REDEMPTIDN (a)

L0NG-TERM DEBT (a) 2)626,186 4)259,826 774,193 151 825 3,193,211 3,993,046 838,347 161,443 3,035,027 3,956,563 828,347 145,302 2,961,367 3,849,208 828,347 113,123 3,144,856 3,763,595 828,347 100,130 932,018 999,790 973,649 941,470 928,477 197,000 18,030 1,522,736 197,000 25,030 1,575,220 197,000 32,030 1,591,768 197,000 79,030 1,421,523 197,000 86,030 1,442,070

$3,918,616

$4,411,271

$4,153,281

$3,979,822

$4,107,526 1,292,430 1,218,060 1,118,254 1,018,455 962,670 (a) Including portion due within one year.

Management's Discussion and Analysis of Results of Operations and Financial Condition DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Operating Revenues and Energy Sales Climb Operating revenues rose $23 million in 1989 after a $34 million decrease in 1988. A substantial increase in sales to unaffiliated utilities accounted for the 2% increase in 1989 revenues.

In 1988, revenues decreased 3% primarily from a decrease in wholesale sales partially offset by increased kilo-watthour (kwh) sales to retail customers.

The components of change in revenues are as follows:

Increase (Decrease)

From Previous Year 1989 1988 (in millions)

Retail:

Price variance Volume variance Wholesale:

Price variance Volume variance Other Operating Revenues Total S(18.5)

S(23.2) 10.0 34.6 (8.5) 1 1.4 (48.1)

(4.0)

(41.1) 26.6 (45.1) 4.5 (0.5)

S 22.6 S(34.2)

Results of Operations Net Income Declines Net income decreased to $137 million in 1989 from $152 million in 1988. Although operating revenues increased, the decline in net income was predominantly due to higher op-erating expenses and a decline in nonoperating income.

In 1988 net income decreased

$15 million from 1987 primarily from lower operating income and a decrease in nonoperating income partly offset by reduced interest charges.

Outlook While management believes that the Company as part of the AEP System is well positioned for the 1990's, the outlook is dependent upon the favorable resolution of some uncertain-ties that could adversely affect management's ability to meet its financial obligations and requirements.

These involve the ability to obtain favorable and timely rate-making treatment to recover the Company's cost of service requirements including:

~ The cost of new generating capacity recently placed in service.

~ The cost that could result from new clean air legislation.

Operating Expenses:

Fuel for Electric Generation Purchased and Interchange Power (net)

Other Operation Maintenance Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase. in Costs Taxes Other Than Federal Income Taxes Federal Income Taxes.............

Total S 16.9 S 24.0 (22.1)

(55.1) 9.3 5.2 14.7 (2.2) 4.6 3.2 (1.1) 22.6 0.1 9.5 5.2 (33.8)

S 27.6 S(26.6)

The modest increase in 1989 retail sales volume reflects growth in the number of customers and increased commercial development. The negative effect of mild weather on residen-tial sales throughout most of1989 was offset by unseasonably cold weather in December.

As electric heating and cooling load grows, results of operations become increasingly sen-sitive to weather. Growth of industrial sales volume, which had been steady for the past several years slowed in 1989, reflecting slower economic growth. Higher retail kwh sales in 1988 were attributable to improvement in the economy of the Company's service area coupled with hot summer weather.

The effect on revenues of the higher kwh sales volume was largely offset by a reduction in rates as lower average fuel costs and savings in Federal income taxes were passed on to customers.

The substantial increase in 1989 wholesale sales volume was predominantly due to a significant increase in short-term sales to unaffiliated utilities as a result of growth in their

demand, lower availability of their generating capacity and extremely cold December weather partially offset by a reduc-tion during the year in long-term contract sales to a major wholesale customer. The positive effect of increased whole-sale sales volume on 1989 revenues was partly offset by a lower average price per kwh sold reflecting price competition in the sales for resale market. In 1988, wholesale revenues decreased mostly due to the expiration of a long-term contract with a major wholesale customer. The level of future whole-sale sales can fluctuate with the availability of affiliated and unaffiliated generating units, the effects of weather and the economy on wholesale customers and the competitive nature of the sales for resale market.

Operating Expenses Rise Reflecting Increased Sales Operating expenses increased 4% in 1989 after a 3% de-crease in 1988.

Changes in the components of operating expenses were:

Increase (Decrease)

From Previous Year (in millions) 1989 1988

The increases in fuel expense in both years reflected higher net generation.

The Company was able to significantly de-crease purchased and interchange power expense in 1989 and 1988 due to the increased availability of coal-fired gen-eration. The 1989 changes also reflected the return to service ofboth units at the Company's Cook Nuclear Plant while1988 variances included lower net costs per kwh of purchased and interchange power and a slight decrease in the Company's total load requirements.

Other operation expense increased in both years primarily due to the outage of Unit 2 at the Cook Plant from April 1988 to March 1989 to refuel, replace its steam generators and conduct a 10-year anniversary service inspection as required by the Nuclear Regulatory Commission (NRC). Another factor contributing to the increase in other operation expense in1989 was the accrual of lease expense on Rockport Plant Unit 2 (Rockport 2), which was sold and leased back in early De-cember 1989. Maintenance expense increased in 1989 pri-marily due to maintenance performed on the reactor units at the Cook Nuclear Plant.

The large increase during 1988 in amortization of Rockport Plant Unit 1 (Rockport 1) phase-in costs was due to the discontinuance of deferring depreciation on the unit and the commencement of amortization over a 10-year period of the deferred depreciation and deferred return. The Company dis-continued deferring depreciation and recording a deferred return on its investment in Rockport 1 under a phase-in plan in the latter part of1987 as a result of rate orders that included the last component of the Company's Rockport 1 investment in rate base, thereby replacing a deferred non-cash return with an actual cash return.

The increase in Federal income tax expense in 1989 was primarilydue to changes in certain book/tax timing differences accounted for on a flow-through basis. The 1988 decrease in Federal income tax expense was primarily due to a decrease in pre-tax operating income. The reduction in the statutory Federal income tax rate to 34% as a result of the Tax Reform Act of 1986 (TRA) had a minimal effect on earnings since the Company was granted reductions in its annual base rate levels to reflect the reduction. Changes in tax depreciation and repeal of the investment tax credit by TRA resulted in reduced internal cash flow, but net earnings were not materially impacted due to the Company's utilization of deferred tax accounting for these items.

Nonoperating Income Declines Nonoperating income declined in both 1989 and 1988. The 1989 decrease was the result of a one-time credit to income in the fourth quarter of 1988 which recorded interest earned on nuclear decommissioning trust funds from their inception.

In 1988 the decrease was due to the cessation of recording the deferred return on Rockport 1 in 1987 and the effect of a nonrecurring charge relating to wholesale power transactions recorded in 1987.

Allowance For Funds Used During Construction increases Allowance for funds used during construction (AFUDC) in-creased in 1989 and 1988 resulting primarily from additional accumulated Rockport 2 construction expenditures.

AFUDC willbe substantially lower in 1990 since accruals on Rockport 2 ceased effective with the unit's commercial operation on December 1, 1989.

Liquidityand Capital Resources Construction Spending Decreases Expenditures for additions to plant and property amounted to $206 million in 1989, a 36% decrease from 1988 as con-struction on Rockport 2 tapered off and the unit commenced test operation in October 1989. Construction expenditures for the three-year period 1990-1992 are estimated at $443 million exclusive of what would be substantial additional capital ex-penditures if currently proposed acid rain legislation is enacted.

Debt and Preferred Stock Financing The Company funds its substantial annual capital require-ments for construction of new facilities and improvement of existing facilities through a combination of internally gener-ated funds, short-and long-term borrowings and investments in its common equity by its parent AEP. The Company gen-erally issues short-term debt (commercial paper and bank loans) to provide interim financing of construction,expendi-tures in excess of available internally generated.and other funds. The Company then periodically reduces short-term debt with the proceeds of sales of long-term debt and pre-ferred stock securities and investments in its common equity by AEP.

IANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Issuance of senior securities is expected to be modest in the next few years since the Company's projected construc-tion expenditures for 1990-1992 are expected to be financed through internally generated funds excluding the impact of any new acid rain legislation. If any additional amounts are needed they will have to be raised externally through the proceeds of sales of securities and investments in the Com-pany's common equity by AEP. At December 31, 1989, the Company had unused short-term lines of credit of approxi-mately $233 million shared with other AEP System compa-nies. Regulatory provisions limitshort-term debt borrowings to $200 million; however, the Company may request that this limit be raised.

In December 1989 the Company and its affiliate, AEP Gen-erating'ompany (AEGCo), sold their 50% interests in Rock-port 2 and leased back the unit. Net proceeds to the Company from the sale were $ 661 millionafter taxes which the Company used to repay short-term debt, return capital contributions to its parent, repurchase receivables and subsequent to year end repay long-termborrowings, including the redemption of cer-tain publicly-held first mortgage bonds and preferred stocks.

The net gain on the sale did not affect 1989 earnings since it was deferred and is being amortized over the 33-year lease term. The leases have been accounted foras operating leases.

In order'to issue additional long-term debt for purposes other than refunding, the Company must have pre-tax earn-ings equal to at least twice its annual interest charges after giving effect to the issuance of the new debt. To issue addi-tional preferred stock, the Company must have after-tax gross income at least equal to one and one-half times its annual interest and preferred dividend requirements after giving ef-fect to the issuance of the new preferred stock. As a result, the future earnings performance of the Company will impact its ability to finance required construction. As of December 31, 1989, the Company's long-term debt and preferred stock coverage ratios were 2.85 and 2.02, respectively.

Potential New Environmental Costs Congress is considering several acid rain proposals that would require substantial reductions in emissions at certain AEP System coal-fired generating plants including those of the Company. Should this proposed legislation become law, substantial capital and operating costs would be incurred which, if not recovered through the rate-making

process, would adversely affect the Company's results of operations and financial condition.

Regulatory Concerns The electric utility industry operates in a regulatory envi-ronment that makes it difficultto predict whether the cost of major new generating and transmission capacity additions will be fully recovered in rates.

This is of concern to the Company since it and AEGCo recently completed construction of Rockport 2, which was placed in service in December1989.

In July 1989 the Company filed a request with the Indiana UtilityRegulatory Commission (IURC) for a $60 millionannual rate increase to recover, among other things, the Company's Indiana jurisdictional share of the cost of 385 megawatts (MW) of Rockport 2 capacity, based on the assumption that 720 MW would be sold to unaffiliated utilities. An order is not expected until mid-1990.

In January 1990 the Company began supplying an unaffil-iated utilitywith 250 MW of Rockport 2 capacity under a 20-year unit power agreement subject to final approval by the Federal Energy Regulatory Commission (FERC). Earlier efforts to sell 470 MW of additional capacity under long-term unit power agreements were unsuccessful.

Based on recent load growth forecasts and uncertainties over acid rain legislation, the Company no longer plans to sell this capacity on a long-term basis. AEP System Power Pool member companies will

share the cost of the 470 MW of unsold capacity through the Pool. The recovery of the cost of Rockport 2 in all jurisdictions is subject to regulatory filings and proceedings.

If the Com-pany is unable to recover its share of the costs through the rate-making process or from its share of increased short-term AEP System Pool sales to unaffiliated utilities, it would have an adverse effect on the Company's earnings and possibly its financial condition.

In February 1990 the Supreme Court of Indiana overruled an appeals court and reversed an IURC order that had as-signed a major industrial customer to the Company's service territory. The Company has petitioned the Supreme Court for rehearing; however, ifthe petition were rejected, the Company could lose approximately $7 million of revenues annually.

FERC has proposed various forms of competition in the electric utility industry including proposed rules to create a

new class of power producers exempt from most forms of rate regulation. These "independent power producers" could enter or leave the market as their interests and financial con-ditions dictate. They would be under no legal obligation to serve beyond the limits of a specific contract while electric utilities are obligated to provide their customers with all of their current and future power needs.

If utilities become agents that do not manage their power supply, reliabilitycould be impaired. Since reliability of electric service is of para-mount importance under an obligation to serve, the Company has opposed the proposed rules. The long-term effect on the financial condition of the Company cannot be determined if these'or other rules promoting competition are adopted.

Cook Nuclear Plant The Cook Nuclear units have exhibited indications of inter-granular corrosion (IGC) in the steam generator tubing, a condition which has developed in other pressurized water reactors.

This led to a decision to operate Unit 2 at 80%

power and Unit 1 at 90% power as a steam-generator life conservation measure.

In April 1988, Unit 2 was taken out of service to replace the unit's steam generators, refuel the unit and perform the 10-year anniversary service inspection as required by the NRC. The unit returned to service at a 100%

operating level in March 1989. The Company is seeking re-covery in its rate base of the steam generator replacement expenditures in the aforementioned $60 million rate case filed in July 1989 and will seek similar recovery in other jurisdic-tions in its next rate filing. The IGC problem in the Unit 1 steam generators has been occurring at a slower rate than in Unit 2, but it is possible that the Unit 1 steam generators may have to be replaced eventually. However, there are no present plans for such replacement.

The Company has filed an application with the NRC to extend the operating licenses of the Cook Plant units to 2014 for Unit 1 and 2017 for Unit 2.

Effects of inflation Inflation continues to affect the Company, even though the inflation rate has been relatively low in recent years.

Since the rate-making process limits the Company to recovery of the historical cost of assets, economic losses are experienced when the effects of inflation are not recovered on a timely basis from customers.

Such losses are offset partly by the economic gains that result from the repayment of long-term debt with inflated dollars.

New Accounting Standards The Financial Accounting Standards Board's (FASB) new accounting standard on income taxes will require the Com-pany to adopt the liability method of accounting for income taxes in 1992 and will result in a significant increase in total assets and liabilities due to its requirement that deferred in-come taxes be recorded on existing temporary differences previously accounted for on a flow-through basis with sub-stantially offsetting regulatory assets and liabilities. Whether the new standard willbe implemented on a restated or current basis has not yet been determined.

FASB has issued an Exposure Draft proposing a new ac-counting standard that would require a change in accounting for post-retirement benefits other than pensions from an expense-as-paid to an accrual method. This proposal would require the accrual of prior service costs over 17 years with a proposed effective date of 1992. If issued by FASB in its current form, the significantly greater annual expense that would result is not expect'ed to materially impact the Com-pany's financial condition since it is anticipated that it should be either recovered currently through the rate-making process or offset by regulatory assets.

DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income OPERATING REVENUES ELECTRIC Year Ended December 31, 1987 1988 (in thousands)

$1,005,638

$983,066

$1,017,268 OPERATING EXPENSES:

Fuel for Electric Generation Purchased and Interchange Power (net)

Other Operation Maintenance Depreciation and Amortization Amortization (Deferral) of Rockport Plant Unit 1 Phase-in Costs Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses OPERATING INCOME NONOPERATING INCOME:

Allowance for Equity Funds Used During Construction Deferred Return Rockport Plant Unit 1 Other Total Nonoperating Income INCOME BEFORE INTEREST CHARGES 249,886 25,376 170) 855 104,223 124,809 16,961 56,377 46,755 795,242 210,396

'7,972 4,958 32,930 243,326 232,946 47;503 161,532 89,545 120,145 18,089 56,271 41,592 767,623 215,443 27,023 16,431 43,454 258,897 208,931 102,644 156,310 91,807 116,915 (4,488) 46,730 75,373 794,222 223,046 26,055 31,442

~669) 56,828 279,874 INTEREST CHARGES:

Long-term Debt Short-term Debt and Other Allowance for Borrowed Funds Used During Construction Net Interest Charges NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE To COMMON STOCK See Notes to Consolidated Financial Statements.

131,009 7,279

~32,107 106,181 137,145 18,048 119,097 131,093 5,712

~23.297 130,649 6,635

~30.192 113,508 107,092 151,805 18,848 166,366 20,955

$132,957 145,411

.0 Consolidated Balance Sheets ASSETS December 31, 1989 1988 (in thousands)

ELECTRIC UTILITYPLANT:

Production Transmission Distribution General (includes nuclear fuel)

Construction Work in Progress Total Electric Utility Plant Accumulated Provisions for Depreciation and Amortization Net Electric Utility Plant

$2,465,133 777,782 452,780 170,349 52,572 3,918,616 1,292,430 2,626,186

$2,331,581 737,919 423,729 206,068 711,974 4,411,271 1,218,060 3,193,211 OTHER PROPERTY AND INVEsTMENTs 321,215 301,931 CURRENT AssETs:

Cash and Cash Equivalents Special Deposits Restricted Funds Accounts Receivable:

Customers Associated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel at average cost Materials and Supplies at average cost Accrued Utility Revenues Other Total Current Assets 595,487

'f14,350 10,669 23,441 (606) 40,057 32,479 35,885 6,920 858,682 8,425 2,168 39,847 9,087 19,648 (483) 51,289 25,929 27,512 8,649 192,071 DEFERRED DEBITS:

Deferred Income Taxes Deferred Depreciation and Return Rockport Plant Unit 1 Deferred Nuclear Fuel Disposal Costs Other Total Deferred Debits Total See Notes to Consolidated financial Statements.

173,362 131,879 47,822 100,680 26,769 148,840 51,026 79,198 305,833 453,743

$4,259,826

$3,993,046

INDIAN~HIGANPON'ER COMPANY AND SUBSIDIARIES CAPITALIZATIONAND LIABILITIES December 31, 1989 1988 (in thousands)

CAPITALIZATION:

Common Stock No Par Value:

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

Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt Total Capitalization OTHER NONCURRENT LIABILITIES CURRENT LIABILITIES:

Cumulative Preferred Stock Due Within One Year..

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

General Associated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other Total Current Liabilities DEFERRED CREOITS:

Deferred Income Taxes Deferred Investment Tax Credits Deferred Gain on Sale and Leaseback Rockport Plant Unit 2 Other Total Deferred Credits 8

56,584 717,609 157,825 932,018 197,000 1,021,566 2,150,584 190,962 18,030 501,170 52,602 35,811 200,787 36,101 33,247 76,878 954,626 485,444 221,666 241,255 15,289 963,654 56,584 781,763 161,443 999,790 197,000 25,030 1,563,720 2,785,540 207,637 11,500 7,950 27,900 55,210 14,836 4,285 36,353 43,037 47,866 248,937 535,829 194,726 20,377 750,932 C0MMITMENTs ANo C0NTINGENGIEs (Note 10)

Total

$4,259,826

$3,993,046

Consolidated Statements of Cash Flows 1989 Year Ended December 31, 1988 (in thousands) 1987 CASH FLOWS FROM OPERATING ACTIVITIES:

Net Income Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Depreciation and Amortization Amortization (Deferral) of Rockport Plant Unit 1 Phase-in Costs Deferred Income Taxes Deferred State Taxes Rockport Plant Unit 2 Sale and Leaseback Transaction Deferred Investment Tax Credits Allowance for Equity Funds Used During Construction.........

Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net)

Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Amortization of Deferred Nuclear Fuel Disposal Costs..........

Deferred Return Rockport Plant Unit 1 Other (net)

Net Cash Provided by Operating Activities.............

CAsH FLows FR0M INYEsTING ACTIvITIEs:

Plant and Property Additions Allowance for Equity Funds Used During Construction...........

Cash Used for Plant and Property Additions Proceeds from Sale and Leaseback Rockport Plant Unit 2......

Proceeds from Sales of Other Property Net Cash Provided (Used) by Investing Activities.......

CAsH FLows FR0M FINANGING ACTIvITIEs:

Capital Contributions from (returned to) Parent Issuance of Long-term Debt Change in Short-term Debt (net)

Retirement of Cumulative Preferred Stocks Retirement of Long-term Debt Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Used by Financing Activities Net Increase (Decrease) in Cash and Cash Equivalents.............

Cash and Cash Equivalents at Beginning of Year Cash and Cash Equivalents at End of Year Supplemental Disclosure:

Cash Paid During the Year For:

Interest (net of Allowance for Borrowed Funds Used During Construction)

Income Taxes Noncash Investing Activities:

Plant Acquired Under Capital Leases See Notes to Consolidated Financial Statements.

$137,145

$151,805

$166,366 133,551 16,961 (196,977)

(39,943) 27,445 (27,972)

(79,755) 4,682 (8,373) 18,367 196,502 3,204

'6,258 128,191 18,089 3,161 23,672 (27,023) 25,530 16,485 24,064 11,019 (41,913) 5,408 25,945 124,798 (4,488) 13,597 (7,700)

(26,055) 10,952 (14,293)

(2,576)

(402)

(7,274) 12,207 (31,442) 31,603 211,095 (196,824) 27,972 (168,852) 850,000 1,381 682,529 364,433 (276,545)

"27,023 (249,522) 1,117 265,293 (206,941) 26,055 (180,886) 1,816

~248,405)

~179,070)

(63,000)

(35,850)

(7,000)

(62,512)

(119,952)

~18,248) 10,000 50,000 35,850 (7,000)

(74,050)

(116,816)

~19,048) 376,811 (49,925)

(50,917)

(222,005)

(113,232)

~22,607) 587,062 8 425

$595,487 (5,036) 13,461 8,425 4,348 9,113

$ 13,461

$107,124 64,843 9,035

$106,283 67,019 46,791

$107,389 70,655 41,046

~306,562)

~121,064)

~81,875)

DIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, Balance at Beginning of Year Net Income...............

Total 1989

$161,443 137,145 298,588 1988 (in thousands)

$145,302 151,805 297,107 1987

$113,123 166,366 279,489 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

$3.63 Series Total Dividends Net Premium on Reacquisition of Preferred Stock Total Deductions Balance at fnd of Year See Notes to Consolidated Financial Statements.

119)952 495 273 165 2,124 2,716 2,604 838 3,440 3,600 1,793 138) 000 2,763 140,763

$157,825 116,816 495 273 165 2,124 2,716 2,604 1,198 3,440 3,600 2 233 135,664 135,664

$161,443 113,232 495 273 165 2,124 2,716 2,604 1,558 3,440 3,600 2,673 1,307 134,187 134,187

$145,302 13

Notes to Consolidated Financial Statements

1. Significant Accounting Policies:

Principles of Consolidation The consolidated financial statements include the accounts of Indiana Michigan Power Company (the Company) and its wholly owned subsidiaries.

Significant intercompany trans-actions are eliminated in consolidation.

The common stock of the Company is wholly owned by American Electric Power Company, Inc. (AEP).

System ofAccounts The accounting and rates of the Company are subject in certain respects to the requirements of state regulatory com-missions and the Federal Energy Regulatory Commission (FERC). The consolidated financial statements have been pre-pared on the basis of the uniform system of accounts pre-scribed by the FERC.

Electric Uti%'tyPlant; 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), an item not representing cash income, which is defined in the appli-cable regulatory systems of accounts as the net cost of bor-rowed funds used for construction purposes and a reasonable rate on equity funds when so used. The composite rates used by the Company after compounding on a semi-annual basis were 10.5% in 1989, 10.25% in 1988 and 11.5% in 1987.

The Company provides for depreciation on a straight-line basis over the estimated useful lives of the property and de-termines depreciation provisions largely through the use of composite rates by functional class of property.

Operating expenses are charged with the costs of labor, materials, supervision and other costs incurred in maintaining the Company's properties.

Property accounts are charged with the costs of major additions, replacements and better-ments, and the accumulated provisions for depreciation are charged with retirements, together with removal costs less salvage.

Other property and investments are generally stated at cost.

Cash and Cash Equivalents The Company and its subsidiaries consider cash, special deposits, working funds, and temporary cash investments as defined by the FERC to be cash and cash equivalents.

Gen-erally, temporary cash investments include highly liquid in-vestments purchased with a maturity of three months or less.

Income Taxes Deferred income taxes are provided except where not per-mitted by the state commissions and the FERC. The Company is deferring over the life of its plant the effect of tax reductions resulting from investment tax credits utilized in connection with current Federal income tax accruals consistent with rate-making policies.

Operating Revenues The Company accrues unbilled revenues for electric service rendered subsequent to the last billing cycle through month-end.

Fuel Costs The Company bills its fuel costs under fuel recovery mech-anisms designed to reflect in rates changes in costs of fuel as ordered by various regulatory commissions. Accordingly, the Company accrues revenues relating to unrecovered fuel.

Sale of Receivables In December1988 the Company entered into an agreement to sell undivided interests in designated pools of customer accounts receivable and accrued utilityrevenues, with limited

recourse, up to a maximum of $50,000,000 at any one time.

In December 1989 the Company repurchased the undivided interests and terminated the agreement.

Until termination, the Company sold undivided interests in new designated pools as collections reduced previously sold undivided interests. At December 31, 1988 approximately $50,000,000 remained to be collected.

Other In accordance with regulatory approvals, the Company rec-ognizes the gain or loss on reacquired debt in income in the year of reacquisition unless such debt is refinanced in which case the gain or loss is deferred and amortized over the term of the replacement debt.

Debt premium and debt issuance expenses are being am-ortized over the lives of the related debt issues, and the am-ortization thereof is included in other interest charges.

The Company is committed under unit power agreements with affiliates to purchase from AEP Generating Company (AEGCo), an affiliate company, 70% of AEGCo's Rockport Plant capacity unless it is sold to unaffiliated utilities.

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

INDIANAMICHIGANPOWER COMPANY ANO SUBSIOIARIES

2. Rockport Plant:

Unit 1 Phase-in The Company phased in the recovery of its Rockport Plant Unit 1 (Rockport 1) investment in its Indiana and FERC juris-dictions under formal phase-in plans. Rockport1 is a1,300-megawatt (MW) generating unit that began commercial op-eration in December 1984 and is jointly and equally owned by the Company and AEGCo. At December 31, 1989 and

1988, the Company had unamortized deferred returns of

$102,206,000 and

$115,351,000, respectively, and un-amortized deferred depreciation of $29,673,000 and

$33,489,000, respectively. The amounts deferred from 1984 to 1987 are being amortized and recovered in rates on a straight-line basis through 1997 from the Company's Indiana customers and from all but two FERC customers with whom the Company is engaged in a rate proceeding. With respect to the two FERC customers, recovery is being made subject to refund, pursuant to an interim FERC order. In the opinion of management, the ultimate resolution of this proceeding should not have a significant effect on results of operations.

Unit 2 Sale and Leaseback and Rate Matters The Company and AEGCo constructed a second1,300 MW unit at the Rockport Plant (Rockport 2) at a cost of $1.3 billion. The unit began commercial operation on December 1, 1989. On December 7, 1989, the Company and AEGCo sold their respective 50% interests in the unit for $1.7 billion, the estimated fair market value, and leased back 50% interests in Rockport 2 for an initial term of 33 years. The gain from the sale was deferred and is being amortized, including related taxes, over the initial lease term. The leases have been ac-counted for as operating leases.

The Company will receive 1,105 MW of Rockport 2 capac-ity, comprised of 650 MW, its 50% share, and 455 MW it is obligated to purchase from AEGCo under the terms of a long-term unit power agreement.

In July 1989, the Company filed a request with the Indiana UtilityRegulatory Commission for an increase in rates of approximately $60,000,000 annually to recover, among other things, the Company's Indiana ju-risdictional share of the cost of 385 MWof Rockport 2 capacity purchased from AEGCo. The rate request did not seek recov-ery of the cost of the remaining 720 MW of Rockport 2 ca-pacity since it was based on the assumption that the 720 MW would be sold to unaffiliated utilities. An order is expected by mid-1 990.

The Company has entered into a long-term unit power agreement with Carolina Power & Light, an unaffiliated utility, to supply 250 MWof Rockport 2 capacity for a 20 year period that began in January1990.

The FERC has allowed the agree-ment to become effective subject to refund pending a hearing and resultant final order. Earlier efforts to sell on a long-term basis the remaining 470 MWof additional capacity from Rock-port 2 were unsuccessful.

As a result, AEP System Power Pool member companies will share the cost of such unsold capacity through the Pool. The recovery of the Company's share of the cost of Rockport 2 in all of its jurisdictions is subject to regulatory filings and proceedings.

Ifthe Company is unable to recover its cost of Rockport 2 capacity through the rate-making process or from short-term sales to unaffi-liated utilities, it would have an adverse effect on the Com-pany's earnings and possibly its financial condition.

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

3. Federal Income Taxes:

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

Year Ended December 31 ~

1989 1988 1987 (in thousands)

Charged (Credited) to Operating Expenses (net):

Current

$215,793

$11,865

'63,543 Deferred (196,503) 5,563 19,533 Deferred Investment Tax Credits 27,465 24,164 (7,703)

Total 46,755 41.592 75,373 Charged (Credited) to Nonoperating Income (net):

Current 1,234 1 ~186 2,760 Deferred (474)

(2,402)

(5,936)

Deferred Investment Tax Credits (20)

(492) 3 Total 740 (1,708)

(3,173)

Total Federal Income Taxes as Reported S 47,495

$39,884

$72,200 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 in the Consolidated Statements of Income.

Year Ended December 31, Net Income Federal Income Taxes Pre.tax Book Income 1989

$137,145 47,495

$184,640 1988 (in thousands)

$15'I,805 39,884

$191,689 1987

$166,366 72,200

$238,566 Federal Income Taxes on Pre-Tax Book Income at Statutory Rate (34% ln 1989 and 1988 and 40% In 1987)

Increase (Decrease) in Federal Income Taxes Resulting From the Following Items on Which Deferred Taxes Are Not Provided:

Excess of Book Over Tax Depreciation Allowance for Funds Used During Construction and Miscellaneous Items Capitalized on the Books but Deducted for Tax Purposes Deferred Return Rockport Plant Unit 1

Tax Exempt Income Nuclear Decommissioning Trust Funds.............

Other Amortization of Deferred Investment Tax Credits

~

Total Federal Income Taxes as Reported Effective Federal Income Tax Rate 3,017 (12,664) 1,606 (383)

(464)

(6,395)

$ 47,495 25.7%

3,129 (12,079) 2,112 (4,066)

(7,429)

(6,957)

S 39,884 20.8%

5,104 (13,965)

(5,447)

(1,603)

(7,315)

S 72,200 30.3%

S 62,778 S 65,174 S 95,426

NDIANAMICHIGANPOWER COMPANY ANDSUBSIDIARIES z

(4 The following are the principal components of Federal income taxes as reported:

1987 Year Ended December 31, 1989 1988 (in thousands)

Current:

Federal Income Taxes, 5250,867 S43,680 S65,918 Investment Tax Credits (33,840)

(30,629) (b) 385 Total Current Federal Income Taxes 217,027 (a) 13.051 66,303 Deferred:

Depreciation 2,254 4,737 15,328 Allowance for Borrowed Funds Used During Construction and Miscellaneous Items Capitalized.......

7,109 5,186 3,931 Unrecovered and Levelized Fuel (5,453)

(8,278)

(9,327)

Nuclear Decommissioning Costs (514) 16,432 (c)

(4,235)

Unbilled Revenue (3,713)

(4,202)

(2,839)

Deferred Return Rockport Plant Unit 1

(2,864)

(3,538) 5,315 Sale of Rockport Plant Unit 2 (56,863)

Deferred Net Gain Sale of Rockport Plant Unit 2 (128,194)

Other (8,739)

(7,176) 5,424 Total Deferred Federal Income Taxes (196,977) 3,161 13,597 Total Deferred Investment Tax Credits 27.445 (a) 23.672 (b)

(7.700)

Total Federal Income Taxes as Reported S 47,495 S39,884

$72,200 (a) The significant increase in current Federal income taxes resulted from the gain on the sale of Rockport 2. The placing of Rockport 2 in service in December 1989 enabled the Company to utilize significant investment tax credits generated by the sale and leaseback to reduce its taxes payable. The tax effect of both the gain and the credits utilized were deferred.

(b) Based on Internal Revenue Service regulations issued in 1988, the Company elected to claim investment tax credits on qualified progress expenditures on the 1987 tax return and amended tax returns for 1975 through 1986. The current and deferred tax effects recorded during 1988 represent the cumulative effect of this election as well as 1988 current year accruals.

(c) Based on a ruling the Company received from the Internal Revenue Service in 1988, the Company elected to deduct nuclear decommissioning costs on the 1987 tax return and on amended tax returns for the years 1984 through 1986. The current and deferred tax effects recorded during 1988 represent the cumulative effect of this election as well as 1988 current year accruals.

The Company and its subsidiaries join in the filing of a consolidated Federal income tax return with their affiliated companies in the AEP System.

The allocation of the AEP System's current consolidated Federal income tax to the Sys-tem companies is in accordance with Securities and Exchange Commission (SEC) rules under the Public UtilityHolding Com-pany Act of 1935 (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 de-termining taxes currently payable. 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 approximates a separate return result for each company in the consolidated group.

At December 31, 1989, the cumulative net amount of in-come tax timing differences on which deferred taxes have not been provided totaled $471,000,000.

The consolidated Federal income tax returns for the years 1983 and 1984 are being audited by the Internal Revenue Service. Audits of the returns for the years prior to 1983 are settled.

In the opinion of management, the final settlement of open years should not have a material effect on the earnings of the Company.

In December

1987, the Financial Accounting Standards Board issued SFAS 96 "Accounting for Income Taxes" which requires that companies adopt the liability method of ac-counting for income taxes. SFAS 96 must be adopted by the Company by January 1992 on a restated basis or as a cu-mulative effect of an accounting change in the year of adop-tion. When the new standard is adopted, total assets and liabilities will increase significantly to reflect previously un-recorded deferred tax assets and liabilities on temporary dif-ferences previously flowed-through to earnings.

In addition, existing deferred taxes will be adjusted to the level required at the currently existing statutory tax rate. While the com-putations are not yet completed, it is expected that a signif-icant portion of the required deferred income tax adjustments willbe offset by regulatory assets and liabilities. Whether the new standard will be implemented on a restated or current basis has not yet been determined.

17

NOTES TO CONSOLIDATED FINANCIAL-STATEMENTS (Continued) 1989 1988 (in thousands) 1987 Purchased and Interchange Power (net):

Purchased Power:

AEP Generating Company..

Ohio Valley Electric Corporation Unaffiliated Companies...

Interchange Power (net):

AEP System Electric Utilities:

Capacity Charge Energy Charge Unaffiliated Companies Total............

$13,023

$ 3,313 2,797 5,623 21,486 31,076 8,266 13,580 7,478 14,332 9,858 (1.058)

$47,503 28,240 34,751 (2.486)

$102,644 4,558 (17,858)

(1.456)

$25,376 The Company is a member of the AEP System Power Pool which provides for the Company to share the costs and ben-efits 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 generating reserves among the Pool members in proportion to their relative peak demands.

Energy charges and credits are intended to compensate each company for the out-of-pocket cost of receipts and deliveries of energy among the Pool members.

In addition the Company participates through the Pool in short-term wholesale sales to unaffiliated utilities made by the AEP System, with the Company's share being credited to operating revenues.

These credits to reve-nues were $126,065,000,

$74,181,000 and $58,792,000 in 1989, 1988 and 1987, respectively.

The Company participates with other AEP system compa-nies 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 de-mands. Pursuant to the terms of the agreement, the Company recorded in other operation expenses credits of $37,346,000,

$36,996,000 and $26,025,000 for transmission services in 1989, 1988 and 1987, respectively.

4. Related-party Transactions:

Operating revenues-electric shown in the Consolidated Statements of Income include sales of energy to Michigan Power Company, an affiliated utility that is not a member of the AEP System Power Pool, of approximately $32,000,000,

$34,000,000 and $35,000,000 for the years ended December 31, 1989, 1988 and 1987, respectively.

The Company purchases power and engages in interchange power transactions with affiliated and unaffiliated utilities as follows:

Year Ended December 31 ~

American Electric Power Service Corporation provides cer-tain professional services to the Company and its affiliated companies in the AEP System. The costs of the services are determined by the service corporation on a direct-charge basis to the extent practicable and on reasonable bases of proration for indirect costs. The charges for services are made at cost and include no compensation for the use of equity capital, all of which is furnished to the service corporation by AEP. The Company expenses or capitalizes billings from the service corporation depending on the nature of the professional serv-ice rendered.

The service corporation is subject to the reg-ulation of the SEC under the 1935 Act.

5. Common Shareowner's Equity:

In December 1989 the Company returned $63,000,000 of cash capital contributions to its parent from paid-in capital.

The Company received $10,000,000 of capital contributions in 1988.

In 1989, the Company recorded charges of

$1,154,000 to paid-in capital and $2,763,000 to retained earnings representing the write-off of premiums paid in con-nection with the reacquisition of its $3.63 Series Cumulative Preferred Stock. There were no other transactions affecting the common stock or paid-in capital accounts in 1989, 1988 or 1987.

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 of the Company for cash dividends on its common stocks and other purposes. At December 31, 1989, approx-imately $45,900,000 of refained earnings was restricted.

18

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

6. Cumulative Preferred Stock:

At December 31, 1989, authorized shares of cumulative preferred stock were as follows:

Par Value Shares Authorized

$100 2,250,000 25 11,200,000 The cumulative preferred stock is callable at the option of the Company 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.

ln 1987, the Company redeemed and cancelled the entire $3.63 Series consisting of 1,600,000 shares.

A. Cumulative Preferred Stock Not Subject To Mandatory Redemption:

Series 4V 4 56%

4.12%

7.0S%

7.76%

8.68%

$2.15

$2.25 Call Price December 31, 1989

$106.125 102 102.728 102.91 103.44 103.10 26.08 26.13 Par Value

$100 100 100 100 100 100 25 25 Shares Outstanding December 31, 1989 120,000 60,000 40,000 300,000 350,000 300,000 1,600,000 1,600,000 Amount December 31 ~

1989 1988 (in thousands)

S 12,000 S 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 12% (a)

$2.75 (a)

$106 26.38

$100 30,000 30,000 30,000 25 160,000 160,000 160,000 (a) Redeemed February 1, 1990.

B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Number of Shares Redeemed Call Price December 31, Par Year Ended December 31, 1989 Value 1989 1988 1987 Series Shares Outstanding December 31. 1989 47,325 531,900 Amount December 31, 1989 1988 (in thousands)

$ 4,733 S 7,733 13,297 17,297

$18,030

$25,030 19

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

First Mortgage Bonds.......

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

Less Portion Due Within One Year Total 1989 1988 (in thousands)

$1,007,744

$1,019,036 6,492 7,648 80,000 130,000 307,953 307,732 120,547 110,804 1,522,736 1,575,220 501,170 11,500

$1,021,566

$1,563,720 (a) Nuclear Fuel Disposal Costs. See Note 10.

First mortgage bonds outstanding were as follows:

December 31,

1989, 1988 (in thousands)

% Rate Due 4%

1993 August 1....

7rle 1997 February 1...

9%

1997 July 1

7 1998 May 1 8%

2000 April 1 9%

2003 June 1 (a)...

8%

2003 December 1..

9%

2008 March 1 (b)..

13'/i 2013 August 1 (c) 9%

2015-October1(c) 9/4 2016 July 1 (c) 8~/i 2017 February 1...

10%

2017 May1(c)...

Unamortized Discount (net).....

S 42,902 50,000 75,000 35,000 50,000 185,000 40,000 100,000 58,704 100,000 100,000 100,000 75,000 (3,862)

S 42,902 50,000 75,000 35,000 50,000 196,500 40,000 100,000 58,704 100,000 100,000 100,000 75,000 (4,070)

Less Portion Due Within One Year Total 1,019,036 11,500 1,007,744 411

~170 596,574

$1,007,536 (a) The 9'/Bo series due 2003 requires sinking fund payments of

$11,500,000 annually on June 1 ~ through 1991 and $13,500,000 annually on June 1 ~ 1992 through 2002 with the noncumulative option to redeem an ad.

ditional amount in each of the specified years from a minimum of $100,000 to a maximum equal to the scheduled requirement for each year, but with a maximum optional redemption, as to allyears in the aggregate, of$75,000,000.

(b) Redeemed

$65,966,000 February 1, 1990.

(c) Redeemed February 1 ~ 1990.

The indentures relating to the first mortgage bonds contain improvement, maintenance and replacement provisions re-quiring 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%. At December 31, 1989 and 1988, the principal amounts of debentures reacquired in anticipation of sinking fund requirements were $3,408,000 and $2,552,000, respectively. In addition to the sinking fund requirements the Company may call additional debentures of up to $300,000 annually.

7. Long-term Oebt, Lines of Credit, and Compensating Balances:

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

December 31, 9.02% due 1990 (a) 9.10% due 1990 (a) 9.12% due 1990 (b) 9.18% due 1990 (b) 9.28% due 1991....

Total 1989 1988 (in thousands)

S 25,000 25,000 20,000 20,000 20,000 20,000 40,000 40,000

$80,000

$130.000 (a) Redeemed November 30, 1989.

(b) Redeemed February 1, 1990.

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

December 31.

1989 1988 (in thousands)

% Rate Due City of Lawrenceburg, indiana:

8%

2006 July 1 7

2006 May 1 6%

2006 May 1 City of Rockport, Indiana:

9%

2005 June 1....

9%

2010 June 1....

9~/i 2014 August 1...

7% (a) 2014 August 1...

(b) 2014 August 1...

City of Sullivan, Indiana:

7%

2004 May 1 6r/s 2006 May 1 7%

2009 May 1 Unamortized Discount Total

$ 25,000 40,000 12,000

$ 25,000 40,000 12,000 6,500 33,500 50,000 50,000 50,000 6,500 33,500 50,000 50,000 50,000 7,000 25,000 (4,268)

$307,732 7,000 25,000 13,000 (4,047)

$307,953 (a) Adjustable interest rate will change August 1', 1990 and every five years thereafter.

(b) Variable interest rate is determined weekly..The average weighted interest was 7.0% for 1989 and 5.9% for 1988.

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

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

Certain series are supported by letters of credit from a bank which expire in 1990 and 1992.

Portions of the proceeds of the installment purchase con-tracts were deposited with trustees and were used only for specified construction expenditures.

These funds are shown on the balance sheets as special deposits restricted funds.

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

December 31 ~

20

INDIANAMICHIGANPOWER COMPANY t

AND SUBSIDIARIES Long-term debt, excluding premium or discount, outstand-ing at December.31, 1989 is due as follows:

Principal Amount (in thousands) 1990 501,170 1991 51,500 1992 13,500 1993 56,402 1994.....

13,500 Later Years 894,573 Total

$1,530,645 The amount of short-term debt the Company may borrow is limited by the provisions of the 1935 Act to $200,000,000.

The Company had unused short-term bank lines of credit of approximately $233,000,000 and $259,000,000 at December 31, 1989 and 1988, respectively, under which notes could be issued with no maturity more than 270 days. The lines of credit are subject to withdrawal at the banks'ption and are shared with other AEP System companies.

In accordance with informal agreements with the banks, compensating balances of up to 10% or equivalent fees are required to maintain the lines of credit. Substantially all bank balances maintained by the Company compensate the banks for services and for the Company's share of both used and available lines of credit.

8. Leases:

The Company and its subsidiaries, as part of their opera-tions, lease property, plant and equipment for periods up to 35 years.

Most of the leases require the Company and its subsidiaries to pay related property taxes, maintenance costs and other costs of operation. The Company and its subsidi-aries expect that, in the normal course of business, leases generally will be renewed or replaced by other leases.

The majority of the leases have purchase options or renewal op-tions for substantially all of the economic lives of the properties.

The following is an analysis of properties under capital leases and related obligations included in the Company's bal-ance sheet:

December 31, 1989 1988 (in thousands)

Electric UtilityPlant:

Production Oistrlbution General:

Nuclear Fuel (net of amortization).....

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

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

Net Other Property..............

Net Properties under Capital Leases..

Obligations under Capital Leases (a)..

8,835 8,358 14,603 14,603 131,970 35,541 190,472 23,355 167,117 17,134 16,331 803

$167.920 88,328 34,777 146,543 23,783 122,760 16,746 16,529 217

$122,977

$122,977

$167,920 1990 1991 1992 1993 1994 Later Years Total Future Minimum Lease Payments Capital Operating Leases (a)

Leases (b)

(in thousands)

$ 6,979 101,784 5,696 100,913 4,909 90,688 4,338 90,381 3,944 90,010 36,801 2,228,788 62,667

$2,702,564 Less Estimated Interest Element Included Therein................

28.018 Estimated Present Value of Future Minimum Lease Payments..........

$34,649 (a) Capital lease minimum payments do not include leases of nuclear fuel.

Nuclear fuel rentals comprise the unamortized balance of the lessor's cost (approximately $88,328,000) less salvage value, if any, to be paid in proportion to heat produced and carrying charges on the lessor's unrecovered costs. It is contemplated that portions of the presently leased material willbe replenished by additional leased material. Nuclear fuel rentals of $59,212,000, $52,568,000 and $58,670,000 were charged to fuel for electric generation in 1989, 1988 and 1987 ~ respectively.

(b) Operating lease minimum payments include payments for Rockport 2 lease, which began in Oecember 1989.

(a) Includes an estimated $33,247,000 and $43,037,000 at Oecember 31, 1989 and 1988, respectively, due within one year.

Payments made under capital leases include $52,815,000,

$49,014,000 and $55,557,000 of amortization expense for the years ended December 31,

1989, 1988 and

1987, respectively.

Properties and related obligations under operating leases are not included in the Company's balance sheet.

Future minimum lease payments, by year and in the ag-gregate, for capital leases and noncancelable operating leases of the Company and its subsidiaries consisted of the following at December 31, 1989:

21

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

Operating Expenses Clearing and Miscetlaneous Accounts (charged to income or capitalized)

Total 1989 1988 1987 (in thousands)

$11,000

$11,000

$11,000 6,000

$17.000 6,000

$17.000 5,000

$16,000

9. Pension Plan:

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 eligibilityrequirements, for all their employees.

Effective Jan-uary 1, 1989 plan benefits are determined by a formula which considers each participant's highest average earnings, years of accredited service up to a 45-year limitand social security covered compensation.

Previously, plan benefits were deter-mined by a formula which considered each participant's high-est average earnings, years of accredited service and social security benefits. Pension costs for the plan are allocated to each System company on the basis of each company's share of the total System projected benefit obligation. The Company and its subsidiaries'unding policy is to make annual contri-butions to the plan's trust fund equal to the net periodic pension cost to the extent deductible for Federal income tax

purposes, but not less than the minimum required contribution.

Net pension cost of the defined benefit plan for the years ended December 31, 1989, 1988 and 1987 was $1,271,000,

$397,000 and $161,000, respectively.

In addition to providing pension benefits, the Company and its subsidiaries provide certain health care benefits for retired employees.

If they have 10 years of health care plan partici-pation at retirement, substantially all employees of the Com-pany and its subsidiaries may become eligible for these benefits. The cost of retiree health care benefits is recognized as expense when paid. In 1989, 1988 and 1987, the cost of current retiree health care benefits totaled $2,121,000,

$2,048,000 and $1,661,000, 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 the affiliated companies will utilize the properties under such leases in the future.

Rentals for all operating leases are classified approximately as follows:

Year Ended December 31,

10. Commitments and Contingencies:

Construction The construction budget of the Company and its subsidi-aries for the years 1990-1992 is estimated at $443,000,000, and, in connection therewith, commitments have been made.

Litigation In February 1990 the Supreme Court of Indiana overruled an appeals court and reversed an IURC order that had as-signed a major industrial customer to the Company's service territory. The Company has petitioned the Supreme Court for rehearing; however, ifthe petition were rejected, the Company could lose approximately $7 million of revenues annually.

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.

Although the cumulative, long-term effect of changing environmental requirements upon the Company and its sub-sidiaries cannot be estimated at present, compliance with such requirements may make it necessary, at costs which may be substantial, to retrofit existing facilities with additional air-pollution-control equipment; to change fuel supplies to lower sulfur content coal; to construct cooling towers or some other closed-cycle cooling systems; to undertake new meas-ures in connection with the storage, transportation and dis-posal of by-products and wastes; to curtail or cease operations at existing facilities, and to delay the commercial operation of, or make design changes with respect to, facil-ities under construction.

Legislative proposals are pending before the U.S. Congress that expressly seek to control acid rain. If any of these pro-posals become law, significant reductions in the emission of sulfur dioxide and nitrogen oxide from various existing Com-pany generating plants could be required. These reductions would entail very substantial capital and operating costs that, in turn, could necessitate substantial rate increases by the Company. In addition, a number of states and environmental organizations have pending in the courts proceedings under the existing Clean Air Act seeking substantial reductions in the emission of sulfur dioxide in certain midwestern states.

Further, the U.S. Environmental Protection Agency is con-sidering a number of significant policy changes in its rules governing sulfur dioxide emissions.

Adoption of any of the contemplated policy changes could require substantial re-ductions in sulfur dioxide emissions from the Company's coal-fired generating plants.

Failure to obtain favorable rate-making treatment of re-sultant costs could adversely impact results of operations and financial condition.

22

INDIANAMICHIGANPOWER COMPANY t

AND SUBSIDIARIES Nuclear Insurance The Company is subject to the Price-Anderson Act which limits the public liabilityof a licensee of a nuclear plant for a single nuclear incident to the amount of primary liability in-surance available from private sources and an industry ret-rospective deferred premium assessment plan. The Company maintains the maximum private insurance available of

$200,000,000 for its two-unit Donald C. Cook Nuclear Plant (Cook Plant). Amendments to the Price-Anderson Act, effec-tive August 1988, increased the limits of public liability to

$7,741,100,000 based on 114 reactors currently being sub-ject to the Act. The maximum standard deferred premium that the Company may be assessed, in the event of a nuclear incident at any licensed nuclear power plant in the United

States, is $63,000,000 per reactor, but an assessment may not exceed $10,000,000 in any one year. If public liability claims and authorized legal costs exceed the amount of lia-bilityinsurance and deferred premiums, a licensee must pay a surcharge of up to 5 percent of the standard deferred pre-mium for such claims and costs. Thus, ifdamages in excess of private insurance result from a nuclear incident, the Com-pany could be assessed its pro rata share of the liability up to a maximum of $126,000,000 for its two reactors, in annual installments of $20,000,000, plus $6,300,000 for excess claims and costs. There is no limiton the number of incidents for which the Company could be assessed these sums.

The Company also has property insurance for damage to the Cook Plant facilities in the amount of $2 billion. The pri-mary layer of $500,000,000 is provided through nuclear in-surance pools. The excess coverage above $500,000,000 is provided through insurance pools ($560,000,000) and Nu-clear Electric Insurance Limited (NEIL). NEIL's excess prop-erty insurance program provides $975,000,000 in coverage.

The maximum assessment under this program could be

$8,100,000 (seven and one-half times the annual premium on a 100% coverage basis).

NEIL's extra-expense program provides insurance to cover extra costs of replacement power resulting from a prolonged accidental outage of a nuclear unit. The Company's policy insures against such increased costs up to approximately

$2,350,000 per week (starting 21 weeks after the outage) for one year and $1,575,000 per week for the second year, and

$775,000 per week for the third year, or 80% of those amounts per unit if both units are down for the same reason.

The Company would be subject to a retrospective premium of up to $6,868,000 (five times the annual premium) ifNEIL's losses exceeded its accumulated funds.

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 Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities which are not completely insured, unless allowed to be recovered through rates, could have a material adverse effect on the financial condition of the Company.

Disposal of Spent Nuclear Fuel and Nuclear Decommissioning The Nuclear Waste Policy Act establishes Federal respon-sibility for the permanent disposal of spent nuclear fuel. Dis-posal costs are paid by fees assessed against owners of nuclear plants and deposited into the Nuclear Waste Fund created by the Act. In June 1983, the Company entered into a contract with the U.S. Department of Energy (DOE) for the disposal of spent nuclear fuel. Under terms of the contract, for the disposal of nuclear fuel consumed after April 6, 1983 by the Cook Plant, the Company must pay to the fund a fee of one mill per kilowatthour, which the Company is currently recovering from its customers.

For the disposal of nuclear fuel consumed prior to April 7, 1983, the Company must pay over a period of 10 years to the U.S. Treasury a fee estimated at approximately $71,964,000, exclusive of interest.

The Company has deferred this amount plus accrued interest on its balance sheet and has received regulatory approval for the recovery ofthis amount and is amortizing the amount deferred as it is being recovered ($9,000,000 collected in 1989). Be-cause of the current uncertainties of DOE's program for per-manent disposal of spent nuclear fuel, the Company has not yet commenced paying this fee.

The Company has received regulatory approval from all of its jurisdictions for the recovery of nuclear decommissioning costs associated with the Cook Plant which amounted to

$9,000,000 before income taxes in 1989. An independent consulting firm employed by the Company has estimated that the cost of decommissioning the Cook Plant could range from

$330,000,000 to $369,000,000 in 1989 dollars. The Com-pany intends to reevaluate periodically amounts collected for such costs and to seek regulatory approval to revise such amounts as necessary.

Funds recovered through the rate-making process for dis-posal of spent nuclear fuel consumed prior to April 7, 1983 and for nuclear decommissioning have been deposited in ex-ternal funds for the future payment of such costs.

23

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Concluded)

Real and Personal Property Taxes State Gross Receipts, Excise and Franchise Taxes and Miscellaneous State and Local Taxes...........

State Income Taxes Social Security Taxes Deferred Taxes Rockport 2 Sale and Leaseback Transaction Total

$31,897

$32,339

$28,002 29,282 28,057 7,084 12,361 4,913 6,658 9,383 3,306 6,039 (39.943)

$56,377

$56.271

$46,730 11 ~ Supplementary Income Statement Information:

Taxes other than Federal income taxes include the following items:

Year Ended December 31 ~

1989 1988 1987 (in thousands) 1989 March 31...........

June 30............

September 30........

December 31 1988 March 31...........

June 30............

September 30........

December 31

$257,688

$51,568 244,738 46,239 249,761 56,242 253,451 56,347 243,617 224,026 266,690 248,733 66,340 48,167 58,860 42,076

$36,352 28,028 40,357 32,408 46,498 28,871 39,848 36,588

12. Unaudited Quarterly Financial Information:

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

Quarterly Periods Operating Operating I(et Ended Revenues income Income (in thousands) 24

INDIANAMICHIGANPOYlIER COMPANY t

AND SUBSIDIARIES Independent Auditors'eport 85IIIII@

T()i(iiche 155 East Broad Street Facsimile: (614) 2294647 Columbus, Ohio 43215-3650 Telephone: (614) 221-1000 To the Shareowners and Board of Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries as of December 31, 1989 and 1988, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1989.

These financial statements are the responsibility of the Company's management.

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

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

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

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

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 1989 and

1988, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1989 in conformity with generally accepted accounting principles.

~F~~

rA'ebruary 20, 1990 25

Operating Statistics 1989 1988 1987 1986 1985 ELEGTRIG OPERATING REVENUEs (in thousands):

From Kilowatt-hour Sales:

Retail:

Residential:

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

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

Total from Kilowatt-hour Sales.....

Provision for Revenue Refunds.........

Total Net of Provision for Revenue Refunds............

Other Operating Revenues Total Electric Operating Revenues 182,786 93,291 276,077 196,404

'33,990 11,475 717,946 274,916

$189,845 96,145 285,990 194982 233,855 11,645 726,472 248,283 186,418 90,261 276,679 19'I,352 235,470 11,533 715,034 293,379 174,550 90,881 265,431 184,276 219,344 11,171 680,222 400,779 175,534 90,949 266,483 181,240 213,161 11,234 672,118 396,980 992,862 974,755

~1,800) 1,008,413 1,081,001 1,069,098 541 ~105) 992,862 12,776 1,008,413 8,855 972,955 10,111 1,081,542 9,753 1,068,993 9,800

$1,005,638

$983,066

$1,017,268

$1,091,295

$1,078,793 S0URGEs AND SALEs 0F ENERGY (in millions of kilowatt-hours):

Sources:

Net Generated Steam:

Fossil Fuel Nuclear Fuel Net Generated Hydroelectric...

Subtotal Purchased Net Interchange 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 10,634 12,094 97 22,825 2,229

~1,942) 23,112 1,606 21,506 2,792 1,585 4,377 3,375 5,168 228 13,148 8,358 21,506 8,707 9,791 70 18,568 1,700 737 21,005 1,630 19,375 2,825 1,571 4,396 3,290 5,036 228 12,950 6,425 19,375 6,662 10,060 62 16,784 2,558 1,947 21,289 1,456 19,833 2,719 1,445 4,164 3,142 4,834 221 12,361 7,472 19,833 8,187 10,986 79 19,252 4,941 542 24,735 1,645 23,090 2,536 1,442 3,978 3,007 4,371 212 11,568 11,522 23,090 7,933 7,800 74 15,807 3,248 4,948 24,003 1,542 22,461 2,557 1,481 4,038 2,968 4,282 216 11,504 10,957

, 22,461 26

OPERATING STATISTICS (Concluded)

AvERAGE CosT or-FUEL CoNsUMEo (in cents):

Per Million Btu:

Coal Nuclear Overall Per Kilowatt-hour Generated:

Coal Nuclear Overall 1989 164 61 106 1.62

.67 1.11 1988 182 70 120 1.81

.77 1.26 1987 190 75 117 1.87

.84 1.25 1986 185 74 118 1.82

.83 1.25 1985 194 80 136 1.97

.86 1.42 RESIDENTIAL SERVICE AVERAGES:

Annual Kwh Use per Customer:

Total With Electric Heating Annual Electric Bill:

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

Total With Electric Heating 10,434 18,447 658.08

$1,085.56 6.31 5.88 10,596 18,551 10,146 17,341 6.51 6.12 6.64 6.25 689.33 674.13

$1,135.46

$1,083.10 9,813 17,716 654.88

$1,116.86 6.67 6.30 10,050 18,486 663.18

$1,135.42 6.60 6.14 NUMBER 0F ELEGTRIG CUSTDMERS:

Year-End:

Retail:

Residential:

Without Electric Heating....

With Electric Heating......

Total Residential Commercial Industrial Miscellaneous..

Total Retail Wholesale (sales for resale).....

Total Electric Customers..

335,625 87,016 422,641 46,176 4,485 2,026 475,328 50 475,378 332,488 85,635 418,123 45,249 4,479 1,984 469,835 108 469,943 328,937 84,442 413,379 44,207 4,345 1,946 463,877 105 463,982 325,623 82,324 407,947 43,689 3,882 1,846 457,364 106 457,470 322,922 80,734 403,656 43,017 3,701 1,852 452,226 104 452,330 27

Dividends and Price Ranges of Cumulative Preferred Stock By Quarters (1989 and 1988)

Cumulative Preferred Stock 1st 1989 Quarters 2nd 3rd 4th 1st 1988 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 S 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 12% 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 S2.25 Series Dividends Paid Per Share Market Price $ Per Share (NYSE) High Low

$2.75 Series Dividends Paid Per Share Market Price S Per Share (NYSE) High Low

$1.14

$1.14

$1.14

$1.14

$1.14

$1.14

$1.14

$1.14

$1.03

$1.03

$1.03

$1.03 S1.03

$1.03

$1.03

$1.03

$1.77

$1.77

$1.77

$1.77

$1.77

$1.77

$1.77

$1.77 71 66%

76 68 77 73%

77'/s 75 77s/s 68'/s 70'I>>

68'/s 70>>/>>

71s/>>

67%

67'/>>

$1.94

$1.94

$1.94

$1.94

$1.94

$1.94

$1.94

$1.94 77s/s 74 85'/>>

741/2 85'/>>

80 84'/s 80%

81s/s 75 77'/s 74'/>>

77'/>>

78s/s 73s/>>

73

$2.17

$2.17

$2.17

$2.17

$2.17

$2.17

$2.17

$2.17 84%

81%

88'/z 81%

92 86 92 89 91'/s 82'/s 86'/s 82%

85'/>>

87'/z 80>>/

81

$3.00

$3.00

$3.00

$3.00

$3.00

$3.00

$3.00

$3.00 103'/s 101 106'/s 102>>/z 106 103 108 104 107 101'/>>

107'/z 103'/s 106 108'/s 102'/z 103

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375

$0.5375 22'/s 21 23 20'/>>

24s/s 22 24 22'/z 25 22 25 23'/s 23'/2 21'I>>

22%

21%

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625

$0.5625 23'/s 21'/z 24 21'/s 24'/s 231/>>

25'/s 23'/s 24'/s 22 24'I>>

22'/z 24 22'/>>

23s/>>

217/s

$0.6875

$0.6875

$0.6875

$0.6875

$0.6875

$0.6875

$0.6875 S0.6875 26'/z 26 27'/

25'/z 27 26'/>>

27'/z 26'/s 27'/s 26'/>>-

27 26'/>>

27%

26'/s

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125

$1.03125 MSE Midwest Stock Exchange OTC Over-the. Counter NYSE New York Stock Exchange Note The above bid and asked quotations represent prices between Market quotations provided by National Quotation Bureau, Inc.

Dash indicates quotation not available.

dealers and do not represent actual transactions.

28

Indiana Michigan Power Service Area and the American Electric Power System Lake Mlc hl yen CHIGAN OHIO INDIANA WEST VIRGINIA KENTUCKY VIRGINIA LEGEND Indiana Michigan Power Co. Area Other AEP operating companies'reas 0

Major power piant TENNESSEE

The Company's Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1990 to shareowners upon written request and at no cost.

Please address such requests to:

Mr. G. C. Dean American Electric Power Service Corporation 1 Riverside Plaza Columbus, Ohio 43215 Transfer Agent and Registrar of Cumulative Preferred Stock First Chicago Trust Company of New York 30 West Broadway, New York, N.Y. 10007-2192 29

ENCLOSURE 2 TO AEP:NRC:0909F INDIANAMICHlGAN POWER COMPANY'S PROJECTED CASH FLOW

1990 Internal Cash Flow Projection for Donald C. Cook Nuclear Plant

($ Millions)

Actual 1989 Projected 1990 Net income after taxes Less'ividends paid Retained earnings Adjustments:

Depreciation and amortization Deferred Federal income taxes and investment tax credits AFUDC Total adjustments Internal cash flow Average quarterly cash flow Average cash balances and short-term investments 137.1 138.2 (1.1) 150.5 26.9 (60.1) 117.3 116.2 29.0 58.7 136 129 7

152 (21)

(

3) 128 135 34 20 Total 87.7 54 0, Ownership in all operating nuclear units:

Unit 1 and Unit 2

100%

Maximum Total Contingent Liability 820.0 million (2 units)

0 0

l S

~'

V pE