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

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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 Document control Branch (Document corral Desk) sam C% ~

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SUBJECT:

Forwards "1989 Annual Rept" & projected cash flow.

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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 INDIANA MICHIGAN 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 oo(

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1989, Annual Report (NOD NA MICHIGAN PQWKR Docket ¹ Accession ¹ tc w 9/8~ p ~~

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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 5-8 Consolidated Statements of Income .

Consolidated Balance Sheets 10-11

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

Background of the Company INDIANA MIGHIGAN 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.

'ANA MICHIGANPOWER COMPANY AND SUBSIDIARIES girectors MARK A. BAILEY (a) GERALD P. MALONEY W. A. BLACK (b) RICHARD C. MENGE RICHARD E. DISBROW R. E. PRATER WILLIAMN. 0'ONOFRIO JOSEPH H. VIPPERMAN (b)

A. R. GLASSBURN (C) W. E. WALTERS M. R. HARRELL (d) W. S. WHITE, JR.

WILLIAMJ. LHOTA (a) DAVID H. WILLIAMS, JR.

Officers W. S. WHITE, JR. RICHARD F. HERING CARL J. MOOS Chairman of the Board Vice President Assistant Secretary and Chief Executive Officer WILLIAMJ. LHOTA (a) JOHN B. SHINNOCK W. A. BLACK (b) Vice President Assistant Secretary President and GERALD P. MALONEY LEONARD V. ASSANTE Chief Operating Officer Vice President Assistant Treasurer RICHARD C. MENGE (a) JOSEPH H. VIPPERMAN (b) BRUCE M. BARBER President and Chief Vice President Assistant Treasurer Operating Officer DAViD H. WiLLIAMS, JR. GERALD R. KNORR MILTON P. ALEXICH Vice President Assistant Treasurer Vice President PETER J. DEMARIA MARK A. BAILEY (e) Treasurer Vice President JOHN F. DILORENZO, JR.

RICHARD E. DISBROW Secretary Vice President ELIO BAFILE WILLIAMN. D'ONOFRIO Assistant Secretary and Vice President Assistant Treasurer A. JOSEPH DOWD JEFFREY D. CROSS Vice President Assistant Secretary 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 of American 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 1986 1985 (in thousands)

INCOME STATEMENTS DATA:

OPERATING REVENUES ELECTRIC ....... $ 1,005,638 $ 983,066 $ 1,017,268 $ 1,091,295 $ 1,078,793 OPERATING EXPENSES 795,242 767,623 794,222 900,151 886,904 OPERATING INCOME 210,396 215,443 223,046 191,144 191,889 NONOPERATING INCOME . 32 830 43,454 56,828 66,905 76,879 INCOME BEFORE INTEREST CHARGES ....... 243,326 ,

258,897 279,874 258,049 268,768 INTEREST CHARGES . 106,181 107,092 113,508 105,568 122,667 NET INCOME 137,145 151,805 166,366 152,481 146,101 PREFERRED STocK DIYIDEND REQUIREMENTs . 18,048 18,848 20,955 26,256 27,056 EARNINGS APPLICABLE To COMMON STOCK $ 119,097 $ 132,957 $ 145,411 $ 126,225 $ l19,045 December 31, 1989 1988 1987 1986 1985 (in thousands)

BALANCE SHEETS

$ 3,918,616 $ 4,411,271 $ 4,153,281 $ 3,979,822 $ 4,107,526 DATA'LECTRIC UTILITY PLANT .

ACCUMULATED PROVISIONS FOR DEPRECIATION AND AMORTIZATION 1,292,430 1,218,060 1,118,254 1,018,455 962,670 NET ELECTRIC UTILITY PLANT 2)626,186 3,193,211 3,035,027 2,961,367 3,144,856 TOTAL ASSETS . 4)259,826 3,993,046 3,956,563 3,849,208 3,763,595 COMMON STOCK AND PAID-IN CAPITAL ....... 774,193 838,347 828,347 828,347 828,347 RETAINED EARNINGS 151 825 161,443 145,302 113,123 100,130 TOTAL COMMON SHAREOWNER S EOUITY ...... 932,018 999,790 973,649 941,470 928,477 CUMULATIVE PREFERRED STOCK:

NOT SUBJECT To MANDATORY REDEMPTION 197,000 197,000 197,000 197,000 197,000 SUBJECT To MANDAT0RY REDEMPTIDN (a) 18,030 25,030 32,030 79,030 86,030 L0NG-TERM DEBT (a) 1,522,736 1,575,220 1,591,768 1,421,523 1,442,070 (a) Including portion due within one year.

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Management's Discussion and Analysis of Results of Operations and Financial Condition Results of Operations The modest increase in 1989 retail sales volume reflects growth in the number of customers and increased commercial Net Income Declines development. The negative effect of mild weather on residen-Net income decreased to $ 137 million in 1989 from $ 152 tial sales throughout most of1989 was offset by unseasonably million in 1988. Although operating revenues increased, the cold weather in December. As electric heating and cooling decline in net income was predominantly due to higher op- load grows, results of operations become increasingly sen-erating expenses and a decline in nonoperating income. In sitive to weather. Growth of industrial sales volume, which 1988 net income decreased $ 15 million from 1987 primarily had been steady for the past several years slowed in 1989, from lower operating income and a decrease in nonoperating reflecting slower economic growth. Higher retail kwh sales in income partly offset by reduced interest charges. 1988 were attributable to improvement in the economy of the Company's service area coupled with hot summer weather.

Outlook The effect on revenues of the higher kwh sales volume was While management believes that the Company as part of the largely offset by a reduction in rates as lower average fuel AEP System is well positioned for the 1990's, the outlook is costs and savings in Federal income taxes were passed on to dependent upon the favorable resolution of some uncertain- customers.

ties that could adversely affect management's ability to meet The substantial increase in 1989 wholesale sales volume its financial obligations and requirements. These involve the was predominantly due to a significant increase in short-term ability to obtain favorable and timely rate-making treatment sales to unaffiliated utilities as a result of growth in their to recover the Company's cost of service requirements demand, lower availability of their generating capacity and including: extremely cold December weather partially offset by a reduc-

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The cost of new generating capacity recently placed in tion during the year in long-term contract sales to a major service. wholesale customer. The positive effect of increased whole-

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

sale sales volume on 1989 revenues was partly offset by a lower average price per kwh sold reflecting price competition Operating Revenues and Energy Sales Climb in the sales for resale market. In 1988, wholesale revenues Operating revenues rose $ 23 million in 1989 after a $ 34 decreased mostly due to the expiration of a long-term contract million decrease in 1988. A substantial increase in sales to with a major wholesale customer. The level of future whole-unaffiliated utilities accounted for the 2% increase in 1989 sale sales can fluctuate with the availability of affiliated and revenues. In 1988, revenues decreased 3% primarily from a unaffiliated generating units, the effects of weather and the decrease in wholesale sales partially offset by increased kilo- economy on wholesale customers and the competitive nature watthour (kwh) sales to retail customers. of the sales for resale market.

The components of change in revenues are as follows:

Operating Expenses Rise Reflecting Increased Sales Increase (Decrease)

From Previous Year Operating expenses increased 4% in 1989 after a 3% de-1989 1988 crease in 1988. Changes in the components of operating (in millions) expenses were:

Retail:

Increase (Decrease)

Price variance S(18.5) S(23.2) From Previous Year Volume variance 10.0 34.6 (in millions)

(8.5) 1 1.4 1988 1989 Wholesale:

Operating Expenses:

Price variance (48.1) (4.0) Fuel for Electric Generation S 16.9 S 24.0 Volume variance (41.1) (55.1)

Purchased and Interchange Power (net) . (22.1) 26.6 (45.1) Other Operation 9.3 5.2 Other Operating Revenues 4.5 (0.5) Maintenance 14.7 (2.2)

Depreciation and Amortization 4.6 3.2 Total S 22.6 S(34.2) Amortization of Rockport Plant Unit 1 Phase. in Costs (1.1) 22.6 Taxes Other Than Federal Income Taxes . 0.1 9.5 Federal Income Taxes ............. 5.2 (33.8)

Total S 27.6 S(26.6)

The increases in fuel expense in both years reflected higher Nonoperating Income Declines net generation. The Company was able to significantly de- Nonoperating income declined in both 1989 and 1988. The crease purchased and interchange power expense in 1989 1989 decrease was the result of a one-time credit to income and 1988 due to the increased availability of coal-fired gen- in the fourth quarter of 1988 which recorded interest earned eration. The 1989 changes also reflected the return to service on nuclear decommissioning trust funds from their inception.

ofboth units at the Company's Cook Nuclear Plant while1988 In 1988 the decrease was due to the cessation of recording variances included lower net costs per kwh of purchased and the deferred return on Rockport 1 in 1987 and the effect of a interchange power and a slight decrease in the Company's nonrecurring charge relating to wholesale power transactions total load requirements. recorded in 1987.

Other operation expense increased in both years primarily Allowance For Funds Used During Construction increases due to the outage of Unit 2 at the Cook Plant from April 1988 to March 1989 to refuel, replace its steam generators and Allowance for funds used during construction (AFUDC) in-conduct a 10-year anniversary service inspection as required creased in 1989 and 1988 resulting primarily from additional by the Nuclear Regulatory Commission (NRC). Another factor accumulated Rockport 2 construction expenditures. AFUDC contributing to the increase in other operation expense in1989 will be substantially lower in 1990 since accruals on Rockport was the accrual of lease expense on Rockport Plant Unit 2 2 ceased effective with the unit's commercial operation on (Rockport 2), which was sold and leased back in early De- December 1, 1989.

cember 1989. Maintenance expense increased in 1989 pri-marily due to maintenance performed on the reactor units at Liquidity and Capital Resources the Cook Nuclear Plant. Construction Spending Decreases The large increase during 1988 in amortization of Rockport Plant Unit 1 (Rockport 1) phase-in costs was due to the Expenditures for additions to plant and property amounted discontinuance of deferring depreciation on the unit and the to $ 206 million in 1989, a 36% decrease from 1988 as con-struction on Rockport 2 tapered off and the unit commenced commencement of amortization over a 10-year period of the test operation in October 1989. Construction expenditures for deferred depreciation and deferred return. The Company dis-the three-year period 1990-1992 are estimated at $ 443 million continued deferring depreciation and recording a deferred exclusive of what would be substantial additional capital ex-return on its investment in Rockport 1 under a phase-in plan penditures if currently proposed acid rain legislation is in the latter part of1987 as a result of rate orders that included enacted.

the last component of the Company's Rockport 1 investment in rate base, thereby replacing a deferred non-cash return Debt and Preferred Stock Financing with an actual cash return. The Company funds its substantial annual capital require-The increase in Federal income tax expense in 1989 was ments for construction of new facilities and improvement of primarily due to changes in certain book/tax timing differences existing facilities through a combination of internally gener-accounted for on a flow-through basis. The 1988 decrease in ated funds, short- and long-term borrowings and investments Federal income tax expense was primarily due to a decrease in its common equity by its parent AEP. The Company gen-in pre-tax operating income. The reduction in the statutory erally issues short-term debt (commercial paper and bank Federal income tax rate to 34% as a result of the Tax Reform loans) to provide interim financing of construction,expendi-Act of 1986 (TRA) had a minimal effect on earnings since the tures in excess of available internally generated.and other Company was granted reductions in its annual base rate levels funds. The Company then periodically reduces short-term to reflect the reduction. Changes in tax depreciation and repeal debt with the proceeds of sales of long-term debt and pre-of the investment tax credit by TRA resulted in reduced internal ferred stock securities and investments in its common equity cash flow, but net earnings were not materially impacted due by AEP.

to the Company's utilization of deferred tax accounting for these items.

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Issuance of senior securities is expected to be modest in Potential New Environmental Costs the next few years since the Company's projected construc- Congress is considering several acid rain proposals that tion expenditures for 1990-1992 are expected to be financed would require substantial reductions in emissions at certain through internally generated funds excluding the impact of AEP System coal-fired generating plants including those of any new acid rain legislation. If any additional amounts are the Company. Should this proposed legislation become law, needed they will have to be raised externally through the substantial capital and operating costs would be incurred proceeds of sales of securities and investments in the Com- which, if not recovered through the rate-making process, pany's common equity by AEP. At December 31, 1989, the would adversely affect the Company's results of operations Company had unused short-term lines of credit of approxi- and financial condition.

mately $ 233 million shared with other AEP System compa-nies. Regulatory provisions limit short-term debt borrowings Regulatory Concerns to $ 200 million; however, the Company may request that this The electric utility industry operates in a regulatory envi-limit be raised. ronment that makes it difficult to predict whether the cost of In December 1989 the Company and its affiliate, AEP Gen- major new generating and transmission capacity additions erating'ompany (AEGCo), sold their 50% interests in Rock- will be fully recovered in rates. This is of concern to the port 2 and leased back the unit. Net proceeds to the Company Company since it and AEGCo recently completed construction from the sale were $ 661 million after taxes which the Company of Rockport 2, which was placed in service in December1989.

used to repay short-term debt, return capital contributions to In July 1989 the Company filed a request with the Indiana its parent, repurchase receivables and subsequent to year end UtilityRegulatory Commission (IURC) for a $ 60 million annual repay long-termborrowings, including the redemption of cer- rate increase to recover, among other things, the Company's tain publicly-held first mortgage bonds and preferred stocks. Indiana jurisdictional share of the cost of 385 megawatts The net gain on the sale did not affect 1989 earnings since it (MW) of Rockport 2 capacity, based on the assumption that was deferred and is being amortized over the 33-year lease 720 MW would be sold to unaffiliated utilities. An order is term. The leases have been accounted for as operating leases. not expected until mid-1990.

In order'to issue additional long-term debt for purposes In January 1990 the Company began supplying an unaffil-other than refunding, the Company must have pre-tax earn- iated utility with 250 MW of Rockport 2 capacity under a 20-ings equal to at least twice its annual interest charges after year unit power agreement subject to final approval by the giving effect to the issuance of the new debt. To issue addi- Federal Energy Regulatory Commission (FERC). Earlier efforts tional preferred stock, the Company must have after-tax gross to sell 470 MW of additional capacity under long-term unit income at least equal to one and one-half times its annual power agreements were unsuccessful. Based on recent load interest and preferred dividend requirements after giving ef- growth forecasts and uncertainties over acid rain legislation, fect to the issuance of the new preferred stock. As a result, the Company no longer plans to sell this capacity on a long-the future earnings performance of the Company will impact term basis. AEP System Power Pool member companies will 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.

share the cost of the 470 MW of unsold capacity through the tions in its next rate filing. The IGC problem in the Unit 1 Pool. The recovery of the cost of Rockport 2 in all jurisdictions steam generators has been occurring at a slower rate than in is subject to regulatory filings and proceedings. If the Com- Unit 2, but it is possible that the Unit 1 steam generators may pany is unable to recover its share of the costs through the have to be replaced eventually. However, there are no present rate-making process or from its share of increased short-term plans for such replacement.

AEP System Pool sales to unaffiliated utilities, it would have The Company has filed an application with the NRC to an adverse effect on the Company's earnings and possibly its extend the operating licenses of the Cook Plant units to 2014 financial condition. for Unit 1 and 2017 for Unit 2.

In February 1990 the Supreme Court of Indiana overruled Effects of inflation an appeals court and reversed an IURC order that had as-Inflation continues to affect the Company, even though the signed a major industrial customer to the Company's service inflation rate has been relatively low in recent years. Since territory. The Company has petitioned the Supreme Court for the rate-making process limits the Company to recovery of rehearing; however, if the petition were rejected, the Company the historical cost of assets, economic losses are experienced could lose approximately $ 7 million of revenues annually.

when the effects of inflation are not recovered on a timely FERC has proposed various forms of competition in the basis from customers. Such losses are offset partly by the electric utility industry including proposed rules to create a new class of power producers exempt from most forms of economic gains that result from the repayment of long-term rate regulation. These "independent power producers" could debt with inflated dollars.

enter or leave the market as their interests and financial con-ditions dictate. They would be under no legal obligation to New Accounting Standards serve beyond the limits of a specific contract while electric The Financial Accounting Standards Board's (FASB) new utilities are obligated to provide their customers with all of accounting standard on income taxes will require the Com-their current and future power needs. If utilities become pany to adopt the liability method of accounting for income agents that do not manage their power supply, reliability could taxes in 1992 and will result in a significant increase in total be impaired. Since reliability of electric service is of para- assets and liabilities due to its requirement that deferred in-mount importance under an obligation to serve, the Company come taxes be recorded on existing temporary differences has opposed the proposed rules. The long-term effect on the previously accounted for on a flow-through basis with sub-financial condition of the Company cannot be determined if stantially offsetting regulatory assets and liabilities. Whether these'or other rules promoting competition are adopted. the new standard will be implemented on a restated or current basis has not yet been determined.

Cook Nuclear Plant FASB has issued an Exposure Draft proposing a new ac-The Cook Nuclear units have exhibited indications of inter-counting standard that would require a change in accounting granular corrosion (IGC) in the steam generator tubing, a for post-retirement benefits other than pensions from an condition which has developed in other pressurized water expense-as-paid to an accrual method. This proposal would reactors. This led to a decision to operate Unit 2 at 80% require the accrual of prior service costs over 17 years with power and Unit 1 at 90% power as a steam-generator life a proposed effective date of 1992. If issued by FASB in its conservation measure. In April 1988, Unit 2 was taken out of current form, the significantly greater annual expense that service to replace the unit's steam generators, refuel the unit would result is not expect'ed to materially impact the Com-and perform the 10-year anniversary service inspection as pany's financial condition since it is anticipated that it should required by the NRC. The unit returned to service at a 100% be either recovered currently through the rate-making process operating level in March 1989. The Company is seeking re- or offset by regulatory assets.

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-

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Year Ended December 31, 1988 1987 (in thousands)

OPERATING REVENUES ELECTRIC $ 1,005,638 $ 983,066 $ 1,017,268 OPERATING EXPENSES:

Fuel for Electric Generation . 249,886 232,946 208,931 Purchased and Interchange Power (net) . 25,376 47;503 102,644 Other Operation 170) 855 161,532 156,310 Maintenance 104,223 89,545 91,807 Depreciation and Amortization 124,809 120,145 116,915 Amortization (Deferral) of Rockport Plant Unit 1 Phase-in Costs . 16,961 18,089 (4,488)

Taxes Other Than Federal Income Taxes . 56,377 56,271 46,730 Federal Income Taxes 46,755 41,592 75,373 Total Operating Expenses . 795,242 767,623 794,222 OPERATING INCOME 210,396 215,443 223,046 NONOPERATING INCOME:

Allowance for Equity Funds Used During Construction '7,972 27,023 26,055 Deferred Return Rockport Plant Unit 1 31,442 Other . 4,958 16,431 ~669)

Total Nonoperating Income 32,930 43,454 56,828 INCOME BEFORE INTEREST CHARGES 243,326 258,897 279,874 INTEREST CHARGES:

Long-term Debt 131,009 130,649 131,093 Short-term Debt and Other 7,279 6,635 5,712 Allowance for Borrowed Funds Used During Construction ~32,107 ~30.192 ~23.297 Net Interest Charges 106,181 107,092 113,508 NET INCOME 137,145 151,805 166,366 PREFERRED STOCK DIVIDEND REQUIREMENTS 18,048 18,848 20,955 EARNINGS APPLICABLE To COMMON STOCK . $ 119,097 $ 132,957 $ 145,411 See Notes to Consolidated Financial Statements.

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

ASSETS ELECTRIC UTILITY PLANT:

Production $ 2,465,133 $ 2,331,581 Transmission 777,782 737,919 Distribution 452,780 423,729 General (includes nuclear fuel) . 170,349 206,068 Construction Work in Progress . 52,572 711,974 Total Electric Utility Plant . 3,918,616 4,411,271 Accumulated Provisions for Depreciation and Amortization 1,292,430 1,218,060 Net Electric Utility Plant 2,626,186 3,193,211 OTHER PROPERTY AND INVEsTMENTs 321,215 301,931 CURRENT AssETs:

Cash and Cash Equivalents 595,487 8,425 Special Deposits Restricted Funds 2,168 Accounts Receivable:

Customers 'f14,350 39,847 Associated Companies 10,669 9,087 Miscellaneous 23,441 19,648 Allowance for Uncollectible Accounts . (606) (483)

Fuel at average cost 40,057 51,289 Materials and Supplies at average cost 32,479 25,929 Accrued Utility Revenues 35,885 27,512 Other . 6,920 8,649 Total Current Assets 858,682 192,071 DEFERRED DEBITS:

Deferred Income Taxes 173,362 26,769 Deferred Depreciation and Return Rockport Plant Unit 1 131,879 148,840 Deferred Nuclear Fuel Disposal Costs 47,822 51,026 Other . ............ . 100,680 79,198 Total Deferred Debits . 453,743 305,833 Total . $ 4,259,826 $ 3,993,046 See Notes to Consolidated financial Statements.

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

CAPITALIZATIONAND LIABILITIES CAPITALIZATION:

Common Stock No Par Value:

Authorized 2,500,000 Shares Outstanding 1,400,000 Shares 8 56,584 $ 56,584 Paid-in Capital 717,609 781,763 Retained Earnings 157,825 161,443 Total Common Shareowner's Equity 932,018 999,790 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption . 197,000 197,000 Subject to Mandatory Redemption 25,030 Long-term Debt . 1,021,566 1,563,720 Total Capitalization . 2,150,584 2,785,540 OTHER NONCURRENT LIABILITIES 190,962 207,637 CURRENT LIABILITIES:

Cumulative Preferred Stock Due Within One Year .. 18,030 Long-term Debt Due Within One Year . 501,170 11,500 Notes Payable . 7,950 Commercial Paper 27,900 Accounts Payable:

General 52,602 55,210 Associated Companies . 35,811 14,836 Taxes Accrued 200,787 4,285 Interest Accrued . 36,101 36,353 Obligations Under Capital Leases 33,247 43,037 Other . 76,878 47,866 Total Current Liabilities 954,626 248,937 DEFERRED CREOITS:

Deferred Income Taxes 485,444 535,829 Deferred Investment Tax Credits 221,666 194,726 Deferred Gain on Sale and Leaseback Rockport Plant Unit 2 241,255 Other . 15,289 20,377 Total Deferred Credits 963,654 750,932 C0MMITMENTs ANo C0NTINGENGIEs (Note 10)

Total . $ 4,259,826 $ 3,993,046

Consolidated Statements of Cash Flows Year Ended December 31, 1989 1988 1987 (in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:

Net Income . $ 137,145 $ 151,805 $ 166,366 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Depreciation and Amortization . 133,551 128,191 124,798 Amortization (Deferral) of Rockport Plant Unit 1 Phase-in Costs . 16,961 18,089 (4,488)

Deferred Income Taxes . (196,977) 3,161 13,597 Deferred State Taxes Rockport Plant Unit 2 Sale and Leaseback Transaction (39,943)

Deferred Investment Tax Credits 27,445 23,672 (7,700)

Allowance for Equity Funds Used During Construction ......... (27,972) (27,023) (26,055)

Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net) (79,755) 25,530 10,952 Fuel, Materials and Supplies . 4,682 16,485 (14,293)

Accrued Utility Revenues (8,373) 24,064 (2,576)

Accounts Payable 18,367 11,019 (402)

Taxes Accrued 196,502 (41,913) (7,274)

Amortization of Deferred Nuclear Fuel Disposal Costs .......... 3,204 5,408 12,207 Deferred Return Rockport Plant Unit 1 (31,442)

Other (net) 25,945 31,603

'6,258 Net Cash Provided by Operating Activities ............. 211,095 364,433 265,293 CAsH FLows FR0M INYEsTING ACTIvITIEs:

Plant and Property Additions . (196,824) (276,545) (206,941)

Allowance for Equity Funds Used During Construction ........... 27,972 "27,023 26,055 Cash Used for Plant and Property Additions . (168,852) (249,522) (180,886)

Proceeds from Sale and Leaseback Rockport Plant Unit 2 ...... 850,000 Proceeds from Sales of Other Property 1,381 1,117 1,816 Net Cash Provided (Used) by Investing Activities ....... 682,529 ~248,405) ~179,070)

CAsH FLows FR0M FINANGING ACTIvITIEs:

Capital Contributions from (returned to) Parent . (63,000) 10,000 Issuance of Long-term Debt 50,000 376,811 Change in Short-term Debt (net) . (35,850) 35,850 (49,925)

Retirement of Cumulative Preferred Stocks . (7,000) (7,000) (50,917)

Retirement of Long-term Debt (62,512) (74,050) (222,005)

Dividends Paid on Common Stock . (119,952) (116,816) (113,232)

Dividends Paid on Cumulative Preferred Stock . ~18,248) ~19,048) ~22,607)

Net Cash Used by Financing Activities ~306,562) ~121,064) ~81,875)

Net Increase (Decrease) in Cash and Cash Equivalents ............. 587,062 (5,036) 4,348 Cash and Cash Equivalents at Beginning of Year 8 425 13,461 9,113 Cash and Cash Equivalents at End of Year . $ 595,487 $ 8,425 $ 13,461 Supplemental Disclosure:

Cash Paid During the Year For:

Interest (net of Allowance for Borrowed Funds Used During Construction) $ 107,124 $ 106,283 $ 107,389 Income Taxes . 64,843 67,019 70,655 Noncash Investing Activities:

Plant Acquired Under Capital Leases . 9,035 46,791 41,046 See Notes to Consolidated Financial Statements.

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Year Ended December 31, 1989 1988 1987 (in thousands)

Balance at Beginning of Year $ 161,443 $ 145,302 $ 113,123 Net Income ............... 137,145 151,805 166,366 Total 298,588 297,107 279,489 Cash Dividends Declared:

Common Stock . 119)952 116,816 113,232 Cumulative Preferred Stock:

4)/e% Series 495 495 495 4.56% Series 273 273 273 4.12% Series 165 165 165 7.08% Series 2,124 2,124 2,124 7.76% Series 2,716 2,716 2,716 8.68% Series 2,604 2,604 2,604 12% Series 838 1,198 1,558

$ 2.15 Series 3,440 3,440 3,440

$ 2.25 Series 3,600 3,600 3,600

$ 2.75 Series 1,793 2 233 2,673

$ 3.63 Series 1,307 Total Dividends 138) 000 135,664 134,187 Net Premium on Reacquisition of Preferred Stock . 2,763 Total Deductions 140,763 135,664 134,187 Balance at fnd of Year . $ 157,825 $ 161,443 $ 145,302 See Notes to Consolidated Financial Statements.

13

Notes to Consolidated Financial Statements

1. Significant Accounting Policies: Income Taxes Principles of Consolidation Deferred income taxes are provided except where not per-The consolidated financial statements include the accounts mitted by the state commissions and the FERC. The Company of Indiana Michigan Power Company (the Company) and its is deferring over the life of its plant the effect of tax reductions wholly owned subsidiaries. Significant intercompany trans- resulting from investment tax credits utilized in connection actions are eliminated in consolidation. with current Federal income tax accruals consistent with rate-The common stock of the Company is wholly owned by making policies.

American Electric Power Company, Inc. (AEP).

Operating Revenues System of Accounts The Company accrues unbilled revenues for electric service The accounting and rates of the Company are subject in rendered subsequent to the last billing cycle through month-certain respects to the requirements of state regulatory com- end.

missions and the Federal Energy Regulatory Commission (FERC). The consolidated financial statements have been pre- Fuel Costs pared on the basis of the uniform system of accounts pre- The Company bills its fuel costs under fuel recovery mech-scribed by the FERC. anisms designed to reflect in rates changes in costs of fuel as ordered by various regulatory commissions. Accordingly, Electric Uti%'ty Plant; Depreciation and the Company accrues revenues relating to unrecovered fuel.

Amortization; Other Property and Investments Electric utility plant, which is stated at original cost, gen- Sale of Receivables erally is subject to first mortgage liens. In December1988 the Company entered into an agreement The Company capitalizes, as a construction cost, an allow- to sell undivided interests in designated pools of customer ance for funds used during construction (AFUDC), an item accounts receivable and accrued utility revenues, with limited not representing cash income, which is defined in the appli- recourse, up to a maximum of $ 50,000,000 at any one time.

cable regulatory systems of accounts as the net cost of bor- In December 1989 the Company repurchased the undivided rowed funds used for construction purposes and a reasonable interests and terminated the agreement. Until termination, rate on equity funds when so used. The composite rates used the Company sold undivided interests in new designated pools by the Company after compounding on a semi-annual basis as collections reduced previously sold undivided interests. At were 10.5% in 1989, 10.25% in 1988 and 11.5% in 1987. December 31, 1988 approximately $ 50,000,000 remained to The Company provides for depreciation on a straight-line be collected.

basis over the estimated useful lives of the property and de-termines depreciation provisions largely through the use of Other composite rates by functional class of property. In accordance with regulatory approvals, the Company rec-Operating expenses are charged with the costs of labor, ognizes the gain or loss on reacquired debt in income in the materials, supervision and other costs incurred in maintaining year of reacquisition unless such debt is refinanced in which the Company's properties. Property accounts are charged case the gain or loss is deferred and amortized over the term with the costs of major additions, replacements and better- of the replacement debt.

ments, and the accumulated provisions for depreciation are Debt premium and debt issuance expenses are being am-charged with retirements, together with removal costs less ortized over the lives of the related debt issues, and the am-salvage. ortization thereof is included in other interest charges.

Other property and investments are generally stated at cost. The Company is committed under unit power agreements with affiliates to purchase from AEP Generating Company Cash and Cash Equivalents (AEGCo), an affiliate company, 70% of AEGCo's Rockport The Company and its subsidiaries consider cash, special Plant capacity unless it is sold to unaffiliated utilities.

deposits, working funds, and temporary cash investments as Certain prior-period amounts have been reclassified to con-defined by the FERC to be cash and cash equivalents. Gen- form to current-period presentation.

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

INDIANAMICHIGANPOWER COMPANY ANO SUBSIOIARIES

2. Rockport Plant:

Unit 1 Phase-in The Company phased in the recovery of its Rockport Plant The Company has entered into a long-term unit power Unit 1 (Rockport 1) investment in its Indiana and FERC juris- agreement with Carolina Power & Light, an unaffiliated utility, dictions under formal phase-in plans. Rockport1 is a1,300- to supply 250 MW of Rockport 2 capacity for a 20 year period megawatt (MW) generating unit that began commercial op- that began in January1990. The FERC has allowed the agree-eration in December 1984 and is jointly and equally owned ment to become effective subject to refund pending a hearing by the Company and AEGCo. At December 31, 1989 and and resultant final order. Earlier efforts to sell on a long-term 1988, the Company had unamortized deferred returns of basis the remaining 470 MW of additional capacity from Rock-

$ 102,206,000 and $ 115,351,000, respectively, and un- port 2 were unsuccessful. As a result, AEP System Power amortized deferred depreciation of $ 29,673,000 and Pool member companies will share the cost of such unsold

$ 33,489,000, respectively. The amounts deferred from 1984 capacity through the Pool. The recovery of the Company's to 1987 are being amortized and recovered in rates on a share of the cost of Rockport 2 in all of its jurisdictions is straight-line basis through 1997 from the Company's Indiana subject to regulatory filings and proceedings. If the Company customers and from all but two FERC customers with whom is unable to recover its cost of Rockport 2 capacity through the Company is engaged in a rate proceeding. With respect the rate-making process or from short-term sales to unaffi-to the two FERC customers, recovery is being made subject liated utilities, it would have an adverse effect on the Com-to refund, pursuant to an interim FERC order. In the opinion pany's earnings and possibly its financial condition.

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 Utility Regulatory 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 MW of 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.

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, 1989 1988 1987 (in thousands)

Net Income $ 137,145 $ 15'I,805 $ 166,366 Federal Income Taxes 47,495 39,884 72,200 Pre.tax Book Income $ 184,640 $ 191,689 $ 238,566 Federal Income Taxes on Pre-Tax Book Income at Statutory Rate (34% ln 1989 and 1988 and 40% In 1987) . S 62,778 S 65,174 S 95,426 Increase (Decrease) in Federal Income Taxes Resulting From the Following Items on Which Deferred Taxes Are Not Provided:

Excess of Book Over Tax Depreciation . 3,017 3,129 5,104 Allowance for Funds Used During Construction and Miscellaneous Items Capitalized on the Books but Deducted for Tax Purposes (12,664) (12,079) (13,965)

Deferred Return Rockport Plant Unit 1 1,606 2,112 (5,447)

Tax Exempt Income Nuclear Decommissioning Trust Funds............. (383) (4,066)

Other Amortization of Deferred Investment Tax Credits .......... ~

(464)

(6,395)

(7,429)

(6,957)

(1,603)

(7,315)

Total Federal Income Taxes as Reported . $ 47,495 S 39,884 S 72,200 Effective Federal Income Tax Rate 25.7% 20.8% 30.3%

NDIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES z (4 The following are the principal components of Federal income taxes as reported:

Year Ended December 31, 1989 1988 1987 (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 In December 1987, the Financial Accounting Standards consolidated Federal income tax return with their affiliated Board issued SFAS 96 "Accounting for Income Taxes" which companies in the AEP System. The allocation of the AEP requires that companies adopt the liability method of ac-System's current consolidated Federal income tax to the Sys- counting for income taxes. SFAS 96 must be adopted by the tem companies is in accordance with Securities and Exchange Company by January 1992 on a restated basis or as a cu-Commission (SEC) rules under the Public UtilityHolding Com- mulative effect of an accounting change in the year of adop-pany Act of 1935 (1935 Act). These rules permit the allocation tion. When the new standard is adopted, total assets and of the benefit of current tax losses and investment tax credits liabilities will increase significantly to reflect previously un-utilized to the System companies giving rise to them in de- recorded deferred tax assets and liabilities on temporary dif-termining taxes currently payable. The tax loss of the System ferences previously flowed-through to earnings. In addition, parent company, AEP, is allocated to its subsidiaries with existing deferred taxes will be adjusted to the level required taxable income. With the exception of the loss of the parent at the currently existing statutory tax rate. While the com-company, the method of allocation approximates a separate putations are not yet completed, it is expected that a signif-return result for each company in the consolidated group. icant portion of the required deferred income tax adjustments At December 31, 1989, the cumulative net amount of in- will be offset by regulatory assets and liabilities. Whether the come tax timing differences on which deferred taxes have not new standard will be implemented on a restated or current been provided totaled $ 471,000,000. basis has not yet been determined.

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.

17

NOTES TO CONSOLIDATED FINANCIAL-STATEMENTS (Continued)

4. Related-party Transactions: American Electric Power Service Corporation provides cer-tain professional services to the Company and its affiliated Operating revenues-electric shown in the Consolidated Statements of Income include sales of energy to Michigan companies in the AEP System. The costs of the services are Power Company, an affiliated utility that is not a member of determined by the service corporation on a direct-charge basis the AEP System Power Pool, of approximately $ 32,000,000, to the extent practicable and on reasonable bases of proration for indirect costs. The charges for services are made at cost

$ 34,000,000 and $ 35,000,000 for the years ended December 31, 1989, 1988 and 1987, respectively. and include no compensation for the use of equity capital, all The Company purchases power and engages in interchange of which is furnished to the service corporation by AEP. The power transactions with affiliated and unaffiliated utilities as Company expenses or capitalizes billings from the service follows: corporation depending on the nature of the professional serv-ice rendered. The service corporation is subject to the reg-Year Ended December 31 ~

1989 1988 1987 ulation of the SEC under the 1935 Act.

(in thousands)

Purchased and Interchange 5. Common Shareowner's Equity:

Power (net):

Purchased Power: In December 1989 the Company returned $ 63,000,000 of AEP Generating Company .. $ 13,023 -

$ 3,313 $ 2,797 cash capital contributions to its parent from paid-in capital.

Ohio Valley Electric The Company received $ 10,000,000 of capital contributions Corporation 5,623 13,580 31,076 Unaffiliated Companies ... 21,486 7,478 8,266 in 1988. In 1989, the Company recorded charges of Interchange Power (net): $ 1,154,000 to paid-in capital and $ 2,763,000 to retained AEP System Electric Utilities:

earnings representing the write-off of premiums paid in con-Capacity Charge 4,558 14,332 28,240 nection with the reacquisition of its $ 3.63 Series Cumulative Energy Charge (17,858) 9,858 34,751 Preferred Stock. There were no other transactions affecting Unaffiliated Companies (1.456) (1.058) (2.486) the common stock or paid-in capital accounts in 1989, 1988 Total ............ $ 25,376 $ 47,503 $ 102,644 or 1987.

The Company is a member of the AEP System Power Pool Covenants in mortgage indentures, debenture and bank which provides for the Company to share the costs and ben- loan agreements, charter provisions and orders of regulatory efits associated with the System's generating plants. Under authorities place various restrictions on the use of retained the terms of the System Interchange Agreement, capacity earnings of the Company for cash dividends on its common charges and credits are designed to allocate the cost of the stocks and other purposes. At December 31, 1989, approx-System's generating reserves among the Pool members in imately $ 45,900,000 of refained earnings was restricted.

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.

18

INDIANA MICHIGANPOWER 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:

Amount Call Price Shares December 31, Par Outstanding December 31 ~

Series 1989 Value December 31, 1989 1989 1988 (in thousands) 4V $ 106.125 $ 100 120,000 S 12,000 S 12,000 4 56% 102 100 60,000 6,000 6,000 4.12% 102.728 100 40,000 4,000 4,000 7.0S% 102.91 100 300,000 30,000 30,000 7.76% 103.44 100 350,000 35,000 35,000 8.68% 103.10 100 300,000 30,000 30,000

$ 2.15 26.08 25 1,600,000 40,000 40,000

$ 2.25 26.13 25 1,600,000 40,000 40,000

$ 197.000 $ 197,000 B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Number of Shares Redeemed Amount Call Price Shares December 31, Par Year Ended December 31, Outstanding December 31, Series 1989 Value 1989 1988 1987 December 31. 1989 1989 1988 (in thousands) 12% (a) $ 106 $ 100 30,000 30,000 30,000 47,325 $ 4,733 S 7,733

$ 2.75 (a) 26.38 25 160,000 160,000 160,000 531,900 13,297 17,297

$ 18,030 $ 25,030 (a) Redeemed February 1, 1990.

19

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

7. Long-term Oebt, Lines of Credit, and Unsecured promissory notes payable to banks have been Compensating Balances: entered into by the Company as follows:

December 31 Long-term debt by major category was outstanding as ~

1989 1988 follows:

(in thousands)

December 31, 9.02% due 1990 (a) $ S 25,000 1989 1988 9.10% due 1990 (a) 25,000 (in thousands) 9.12% due 1990 (b) 20,000 20,000 First Mortgage Bonds....... $ 1,007,744 $ 1,019,036 9.18% due 1990 (b) 20,000 20,000 Sinking Fund Debentures 6,492 7,648 9.28% due 1991 .... 40,000 40,000 Notes Payable to Banks 80,000 130,000 Total $80,000 $ 130.000 Installment Purchase Contracts . 307,953 307,732 Other Long. term Debt (a) .... 120,547 110,804 (a) Redeemed November 30, 1989.

1,522,736 1,575,220 (b) Redeemed February 1, 1990.

Less Portion Due Within One Year 501,170 11,500 Installment purchase contracts have been entered into by Total $ 1,021,566 $ 1,563,720 the Company in connection with the issuance of pollution (a) Nuclear Fuel Disposal Costs. See Note 10. control revenue bonds by governmental authorities as follows:

December 31.

First mortgage bonds outstanding were as follows:

1989 1988 December 31, 1989, 1988

% Rate Due (in thousands)

(in thousands)

City of Lawrenceburg, indiana:

% Rate Due 8% 2006 July 1 $ 25,000 $ 25,000 4% 1993 August 1 .... S 42,902 S 42,902 7 2006 May 1 40,000 40,000 7rle 1997 February ... 1 50,000 50,000 6% 2006 May 1 12,000 12,000 9% 1997 July 1 75,000 75,000 City of Rockport, Indiana:

7 1998 May 1 35,000 35,000 9% 2005 June 1 .... 6,500 6,500 8% 2000 April 1 50,000 50,000 9% 2010 June 1 .... 33,500 33,500 9% 2003 June 1 (a) ... 185,000 196,500 9~/i 2014 August 1 ... 50,000 50,000 8% 2003 December .. 1 40,000 40,000 7% (a) 2014 August 1 ... 50,000 50,000 9% 2008 March 1 (b) .. 100,000 100,000 (b) 2014 August 1 ... 50,000 50,000 13'/i 2013 August 1 (c) 58,704 58,704 City of Sullivan, Indiana:

9% 2015- October1(c) . 100,000 100,000 7% 2004 May 1 7,000 7,000 9/4 2016 July 1 (c) 100,000 100,000 6r/s 2006 May 1 25,000 25,000 8~/i 2017 February 1 ... 100,000 100,000 7% 2009 May 1 13,000 10% 2017 May1(c) ... 75,000 75,000 Unamortized Discount (4,047) (4,268)

Unamortized Discount (net) ..... (3,862) (4,070)

Total $ 307,953 $ 307,732 1,007,744 1,019,036 Less Portion Due Within One Year 411 ~ 170 11,500 (a) Adjustable interest rate will change August 1', 1990 and every five years Total $ 596,574 $ 1,007,536 thereafter.

(b) Variable interest rate is determined weekly..The average weighted interest (a) The 9'/Bo series due 2003 requires sinking fund payments of was 7.0% for 1989 and 5.9% for 1988.

$ 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.

~

Under the terms of certain installment purchase contracts, ditional amount in each of the specified years from a minimum of $ 100,000 to the Company is required to pay purchase price installments a maximum equal to the scheduled requirement for each year, but with a in amounts sufficient to enable the cities to pay interest on maximum optional redemption, as to all years in the aggregate, of $ 75,000,000.

and the principal (at stated maturities and upon mandatory (b) Redeemed $ 65,966,000 February 1, 1990.

(c) Redeemed February 1 1990.

~

redemption) of related pollution control revenue bonds issued The indentures relating to the first mortgage bonds contain to finance the Company's share of construction of pollution improvement, maintenance and replacement provisions re- control facilities at certain generating plants of the Company.

On certain series the principal is payable at stated maturities quiring the deposit of cash or bonds with the trustee, or in lieu thereof, certification of unfunded property additions. or on the demand of the bondholders at periodic interest The sinking fund debentures are due May 1, 1998 at an adjustment dates.

interest rate of 7'/4%. At December 31, 1989 and 1988, the Certain series are supported by letters of credit from a bank principal amounts of debentures reacquired in anticipation of which expire in 1990 and 1992.

sinking fund requirements were $ 3,408,000 and $ 2,552,000, Portions of the proceeds of the installment purchase con-respectively. In addition to the sinking fund requirements the tracts were deposited with trustees and were used only for Company may call additional debentures of up to $ 300,000 specified construction expenditures. These funds are shown annually. on the balance sheets as special deposits restricted funds.

20

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Long-term debt, excluding premium or discount, outstand- The following is an analysis of properties under capital ing at December.31, 1989 is due as follows: leases and related obligations included in the Company's bal-Principal Amount ance sheet:

(in thousands) December 31, 1990 $ 501,170 1989 1988 1991 51,500 1994.....

(in thousands) 1992 13,500 Electric Utility Plant:

1993 56,402 Production $ 8,835 $ 8,358 13,500 Oistrlbution 14,603 14,603 Later Years 894,573 General:

Total $ 1,530,645 Nuclear Fuel (net of amortization) ..... 88,328 131,970 Other 34,777 35,541 The amount of short-term debt the Company may borrow Total Electric Utility Plant......... 146,543 190,472 is limited by the provisions of the 1935 Act to $ 200,000,000. Accumulated Provisions for Amortization 23,783 23,355 The Company had unused short-term bank lines of credit of Net Electric Utility Plant 122,760 167,117 approximately $ 233,000,000 and $ 259,000,000 at December Other Property 16,746 17,134 31, 1989 and 1988, respectively, under which notes could Accumulated Provisions for Amortization .. 16,529 16,331 be issued with no maturity more than 270 days. The lines of Net Other Property .............. 217 803 credit are subject to withdrawal at the banks'ption and are Net Properties under Capital Leases .. $ 122,977 $ 167.920 shared with other AEP System companies. In accordance with Obligations under Capital Leases (a) .. $ 122,977 $ 167,920 informal agreements with the banks, compensating balances (a) Includes an estimated $ 33,247,000 and $ 43,037,000 at Oecember 31, of up to 10% or equivalent fees are required to maintain the 1989 and 1988, respectively, due within one year.

lines of credit. Substantially all bank balances maintained by Payments made under capital leases include $ 52,815,000, the Company compensate the banks for services and for the

$ 49,014,000 and $ 55,557,000 of amortization expense for Company's share of both used and available lines of credit. the years ended December 31, 1989, 1988 and 1987, respectively.

8. Leases: Properties and related obligations under operating leases The Company and its subsidiaries, as part of their opera- are not included in the Company's balance sheet.

tions, lease property, plant and equipment for periods up to Future minimum lease payments, by year and in the ag-35 years. Most of the leases require the Company and its gregate, for capital leases and noncancelable operating leases subsidiaries to pay related property taxes, maintenance costs of the Company and its subsidiaries consisted of the following and other costs of operation. The Company and its subsidi- at December 31, 1989:

aries expect that, in the normal course of business, leases Capital Operating Leases (a) Leases (b) generally will be renewed or replaced by other leases. The (in thousands) majority of the leases have purchase options or renewal op-1990 $ 6,979 $ 101,784 tions for substantially all of the economic lives of the 1991 5,696 100,913 properties. 1992 4,909 90,688 1993 4,338 90,381 1994 3,944 90,010 Later Years 36,801 2,228,788 Total Future Minimum Lease Payments 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 will be 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.

21

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Continued)

Included in the above analysis of future minimum lease 10. Commitments and Contingencies:

payments and of properties under capital leases and related Construction obligations are certain leases in which portions of the related rentals are paid for or reimbursed by affiliated companies in The construction budget of the Company and its subsidi-the AEP System based on their usage of the leased property. aries for the years 1990-1992 is estimated at $ 443,000,000, The Company and its subsidiaries cannot predict the extent and, in connection therewith, commitments have been made.

to which the affiliated companies will utilize the properties under such leases in the future. Litigation Rentals for all operating leases are classified approximately In February 1990 the Supreme Court of Indiana overruled as follows: an appeals court and reversed an IURC order that had as-Year Ended December 31, signed a major industrial customer to the Company's service 1989 1988 1987 territory. The Company has petitioned the Supreme Court for (in thousands) rehearing; however, if the petition were rejected, the Company Operating Expenses $ 11,000 $ 11,000 $ 11,000 could lose approximately $ 7 million of revenues annually.

Clearing and Miscetlaneous Accounts (charged to income or capitalized) 6,000 6,000 5,000 Environmental Matters Total $ 17.000 $ 17.000 $ 16,000 The Company and its subsidiaries are subject to regulation by Federal, state and local authorities with respect to air- and

9. Pension Plan: water-quality control and other environmental matters, and are subject to zoning and other regulation by local authorities.

The Company and its subsidiaries participate with other Although the cumulative, long-term effect of changing companies in the AEP System in a trusteed, noncontributory environmental requirements upon the Company and its sub-defined benefit plan to provide pensions, subject to certain sidiaries cannot be estimated at present, compliance with eligibility requirements, for all their employees. Effective Jan- such requirements may make it necessary, at costs which uary 1, 1989 plan benefits are determined by a formula which may be substantial, to retrofit existing facilities with additional considers each participant's highest average earnings, years air-pollution-control equipment; to change fuel supplies to of accredited service up to a 45-year limit and social security lower sulfur content coal; to construct cooling towers or some covered compensation. Previously, plan benefits were deter- other closed-cycle cooling systems; to undertake new meas-mined by a formula which considered each participant's high- ures in connection with the storage, transportation and dis-est average earnings, years of accredited service and social posal of by-products and wastes; to curtail or cease security benefits. Pension costs for the plan are allocated to operations at existing facilities, and to delay the commercial each System company on the basis of each company's share operation of, or make design changes with respect to, facil-of the total System projected benefit obligation. The Company ities under construction.

and its subsidiaries'unding policy is to make annual contri- Legislative proposals are pending before the U.S. Congress butions to the plan's trust fund equal to the net periodic that expressly seek to control acid rain. If any of these pro-pension cost to the extent deductible for Federal income tax posals become law, significant reductions in the emission of purposes, but not less than the minimum required sulfur dioxide and nitrogen oxide from various existing Com-contribution. pany generating plants could be required. These reductions Net pension cost of the defined benefit plan for the years would entail very substantial capital and operating costs that, ended December 31, 1989, 1988 and 1987 was $ 1,271,000, in turn, could necessitate substantial rate increases by the

$ 397,000 and $ 161,000, respectively. Company. In addition, a number of states and environmental In addition to providing pension benefits, the Company and organizations have pending in the courts proceedings under its subsidiaries provide certain health care benefits for retired the existing Clean Air Act seeking substantial reductions in employees. If they have 10 years of health care plan partici- the emission of sulfur dioxide in certain midwestern states.

pation at retirement, substantially all employees of the Com- Further, the U.S. Environmental Protection Agency is con-pany and its subsidiaries may become eligible for these sidering a number of significant policy changes in its rules benefits. The cost of retiree health care benefits is recognized governing sulfur dioxide emissions. Adoption of any of the as expense when paid. In 1989, 1988 and 1987, the cost of contemplated policy changes could require substantial re-current retiree health care benefits totaled $ 2,121,000, ductions in sulfur dioxide emissions from the Company's

$ 2,048,000 and $ 1,661,000, respectively. 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

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Nuclear Insurance to be recovered through rates, could have a material adverse The Company is subject to the Price-Anderson Act which effect on the financial condition of the Company.

limits the public liability of a licensee of a nuclear plant for a single nuclear incident to the amount of primary liability in- Disposal of Spent Nuclear Fuel surance available from private sources and an industry ret- and Nuclear Decommissioning rospective deferred premium assessment plan. The Company The Nuclear Waste Policy Act establishes Federal respon-maintains the maximum private insurance available of sibility for the permanent disposal of spent nuclear fuel. Dis-

$ 200,000,000 for its two-unit Donald C. Cook Nuclear Plant posal costs are paid by fees assessed against owners of (Cook Plant). Amendments to the Price-Anderson Act, effec- nuclear plants and deposited into the Nuclear Waste Fund tive August 1988, increased the limits of public liability to created by the Act. In June 1983, the Company entered into

$ 7,741,100,000 based on 114 reactors currently being sub- a contract with the U.S. Department of Energy (DOE) for the ject to the Act. The maximum standard deferred premium that disposal of spent nuclear fuel. Under terms of the contract, the Company may be assessed, in the event of a nuclear for the disposal of nuclear fuel consumed after April 6, 1983 incident at any licensed nuclear power plant in the United by the Cook Plant, the Company must pay to the fund a fee States, is $ 63,000,000 per reactor, but an assessment may of one mill per kilowatthour, which the Company is currently not exceed $ 10,000,000 in any one year. If public liability recovering from its customers. For the disposal of nuclear claims and authorized legal costs exceed the amount of lia- fuel consumed prior to April 7, 1983, the Company must pay bility insurance and deferred premiums, a licensee must pay over a period of 10 years to the U.S. Treasury a fee estimated a surcharge of up to 5 percent of the standard deferred pre- at approximately $ 71,964,000, exclusive of interest. The mium for such claims and costs. Thus, if damages in excess Company has deferred this amount plus accrued interest on of private insurance result from a nuclear incident, the Com- its balance sheet and has received regulatory approval for the pany could be assessed its pro rata share of the liability up recovery of this amount and is amortizing the amount deferred to a maximum of $ 126,000,000 for its two reactors, in annual as it is being recovered ($ 9,000,000 collected in 1989). Be-installments of $ 20,000,000, plus $ 6,300,000 for excess cause of the current uncertainties of DOE's program for per-claims and costs. There is no limit on the number of incidents manent disposal of spent nuclear fuel, the Company has not for which the Company could be assessed these sums. yet commenced paying this fee.

The Company also has property insurance for damage to The Company has received regulatory approval from all of the Cook Plant facilities in the amount of $ 2 billion. The pri- its jurisdictions for the recovery of nuclear decommissioning mary layer of $ 500,000,000 is provided through nuclear in- costs associated with the Cook Plant which amounted to surance pools. The excess coverage above $ 500,000,000 is $ 9,000,000 before income taxes in 1989. An independent provided through insurance pools ($ 560,000,000) and Nu- consulting firm employed by the Company has estimated that clear Electric Insurance Limited (NEIL). NEIL's excess prop- the cost of decommissioning the Cook Plant could range from erty insurance program provides $ 975,000,000 in coverage. $ 330,000,000 to $ 369,000,000 in 1989 dollars. The Com-The maximum assessment under this program could be pany intends to reevaluate periodically amounts collected for

$ 8,100,000 (seven and one-half times the annual premium such costs and to seek regulatory approval to revise such on a 100% coverage basis). amounts as necessary.

NEIL's extra-expense program provides insurance to cover Funds recovered through the rate-making process for dis-extra costs of replacement power resulting from a prolonged posal of spent nuclear fuel consumed prior to April 7, 1983 accidental outage of a nuclear unit. The Company's policy and for nuclear decommissioning have been deposited in ex-insures against such increased costs up to approximately ternal funds for the future payment of such costs.

$ 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) if NEIL'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 23

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS (Concluded) 11 ~ Supplementary Income Statement Information: 12. Unaudited Quarterly Financial Information:

Taxes other than Federal income taxes include the following The following consolidated quarterly financial information items: is unaudited but, in the opinion of the Company, includes all Year Ended December 31 ~ adjustments.(consisting of only normal recurring accruals) 1989 1988 1987 necessary for a fair presentation of the amounts shown:

(in thousands) Quarterly Periods Operating Operating I(et Real and Personal Property Ended Revenues income Income Taxes $ 31,897 $ 32,339 $ 28,002 (in thousands)

State Gross Receipts, Excise 1989 and Franchise Taxes and March 31 ........... $ 257,688 $ 51,568 $ 36,352 Miscellaneous State and

........... June 30 ............ 244,738 46,239 28,028 Local Taxes State Income Taxes 29,282 28,057 12,361 4,913 9,383 3,306 September 30 ........ 249,761 56,242 40,357 December 31 253,451 56,347 32,408 Social Security Taxes 7,084 6,658 6,039 1988 Deferred Taxes Rockport 2 March 31 ........... 243,617 66,340 46,498 Sale and Leaseback June 30 ............ 224,026 48,167 28,871 Transaction Total (39.943)

$ 56,377 $ 56.271 $ 46,730 September 30 ........ 266,690 58,860 39,848 December 31 248,733 42,076 36,588 24

Independent Auditors'eport t INDIANAMICHIGANPOYlIER COMPANY AND SUBSIDIARIES 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~~

20, 1990 rA'ebruary 25

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

From Kilowatt-hour Sales:

Retail:

Residential:

Without Electric Heating ........... 182,786 $ 189,845 186,418 $ 174,550 175,534 With Electric Heating 93,291 96,145 90,261 90,881 90,949 Total Residential 276,077 285,990 276,679 265,431 266,483 Commercial . 196,404 194982 19'I,352 184,276 181,240 Industrial '33,990 233,855 235,470 219,344 213,161 Miscellaneous 11,475 11,645 11,533 11,171 11,234 Total Retail . 717,946 726,472 715,034 680,222 672,118 Wholesale (sales for resale) ............ 274,916 248,283 293,379 400,779 396,980 Total from Kilowatt-hour Sales ..... 992,862 974,755 1,008,413 1,081,001 1,069,098 Provision for Revenue Refunds ......... ~1,800) 541 ~105)

Total Net of Provision for Revenue Refunds ............ 992,862 972,955 1,008,413 1,081,542 1,068,993 Other Operating Revenues 12,776 10,111 8,855 9,753 9,800 Total Electric Operating Revenues . $ 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 . 10,634 8,707 6,662 8,187 7,933 Nuclear Fuel 12,094 9,791 10,060 10,986 7,800 Net Generated Hydroelectric ... 97 70 62 79 74 Subtotal 22,825 18,568 16,784 19,252 15,807 Purchased 2,229 1,700 2,558 4,941 3,248 Net Interchange ~1,942) 737 1,947 542 4,948 Total Sources . 23,112 21,005 21,289 24,735 24,003 Less: Losses, Company Use, Etc. . 1,606 1,630 1,456 1,645 1,542 Net Sources 21,506 19,375 19,833 23,090 22,461 Sales:

Retail:

Residential:

Without Electric Heating . 2,792 2,825 2,719 2,536 2,557 With Electric Heating 1,585 1,571 1,445 1,442 1,481 Total Residential 4,377 4,396 4,164 3,978 4,038 Commercial . 3,375 3,290 3,142 3,007 2,968 Industrial 5,168 5,036 4,834 4,371 4,282 Miscellaneous 228 228 221 212 216 Total Retail . 13,148 12,950 12,361 11,568 11,504 Wholesale (sales for resale) .. 8,358 6,425 7,472 11,522 10,957 Total Sales . 21,506 19,375 19,833 23,090 , 22,461 26

OPERATING STATISTICS (Concluded) 1989 1988 1987 1986 1985 AvERAGE CosT or- FUEL CoNsUMEo (in cents):

Per Million Btu:

Coal . 164 182 190 185 194 Nuclear . 61 70 75 74 80 Overall 106 120 117 118 136 Per Kilowatt-hour Generated:

Coal . 1.62 1.81 1.87 1.82 1.97 Nuclear . .67 .77 .84 .83 .86 Overall 1.11 1.26 1.25 1.25 1.42 RESIDENTIAL SERVICE AVERAGES:

Annual Kwh Use per Customer:

Total 10,434 10,596 10,146 9,813 10,050 With Electric Heating . 18,447 18,551 17,341 17,716 18,486 Annual Electric Bill:

Total $ 658.08 $ 689.33 $ 674.13 $ 654.88 $ 663.18 With Electric Heating . $ 1,085.56 $ 1,135.46 $ 1,083.10 $ 1,116.86 $ 1,135.42 Price per Kwh (in cents):

Total . 6.31 6.51 6.64 6.67 6.60 With Electric Heating . 5.88 6.12 6.25 6.30 6.14 NUMBER 0F ELEGTRIG CUSTDMERS:

Year-End:

Retail:

Residential:

Without Electric Heating .... 335,625 332,488 328,937 325,623 322,922 With Electric Heating ...... 87,016 85,635 84,442 82,324 80,734 Total Residential 422,641 418,123 413,379 407,947 403,656 Commercial . 46,176 45,249 44,207 43,689 43,017 Industrial 4,485 4,479 4,345 3,882 3,701 Miscellaneous .. 2,026 1,984 1,946 1,846 1,852 Total Retail 475,328 469,835 463,877 457,364 452,226 Wholesale (sales for resale) ..... 50 108 105 106 104 Total Electric Customers .. 475,378 469,943 463,982 457,470 452,330 27

Dividends and Price Ranges of Cumulative Preferred Stock By Quarters (1989 and 1988) 1989 Quarters 1988 Quarters 1st 2nd 3rd 4th 1st 2nd 3rd 4th Cumulative Preferred Stock

($ 100 Par Value) 4>>/s% Series Dividends Paid Per Share $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 $ 1.03125 Market Price $ Per Share (MSE) High Low 4.56% Series Dividends Paid Per Share $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 $ 1.14 Market Price $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 4.12% Series Dividends Paid Per Share $ 1.03 $ 1.03 $ 1.03 $ 1.03 S1.03 $ 1.03 $ 1.03 $ 1.03 Market Price S Per Share (OTC)

Ask (high/low)

Bid (high/low) 7.08% Series Dividends Paid Per Share $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 Market Price S Per Share (NYSE) High 71 76 77 77'/s 77s/s 70'I>> 70>>/>> 71s/>>

Low 66% 68 73% 75 68'/s 68'/s 67% 67'/>>

7.76% Series Dividends Paid Per Share $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 $ 1.94 Market Price $ Per Share (NYSE) High 77s/s 85'/>> 85'/>> 84'/s 81s/s 77'/s 77'/>> 78s/s Low 74 741/2 80 80% 75 74'/>> 73s/>> 73 8.68% Series Dividends Paid Per Share $ 2.17 $ 2.17 $ 2.17 $ 2.17 $ 2.17 $ 2.17 $ 2.17 $ 2.17 Market Price $ Per Share (NYSE) High 84% 88'/z 92 92 91'/s 86'/s 85'/>> 87'/z Low 81% 81% 86 89 82'/s 82% 80>>/ 81 12% Series Dividends Paid Per Share $ 3.00 $ 3.00 $3.00 $ 3.00 $3.00 $ 3.00 $ 3.00 $ 3.00 Market Price $ Per Share (NYSE) High 103'/s 106'/s 106 108 107 107'/z 106 108'/s Low 101 102>>/z 103 104 101'/>> 103'/s 102'/z 103

($ 25 Par Value)

$ 2.15 Series Dividends Paid Per Share $ 0.5375 $ 0.5375 $ 0.5375 $ 0.5375 $ 0.5375 $ 0.5375 $ 0.5375 $ 0.5375 Market Price $ Per Share (NYSE) High 22'/s 23 24s/s 24 25 25 23'/2 22%

Low 21 20'/>> 22 22'/z 22 23'/s 21'I>> 21%

S2.25 Series Dividends Paid Per Share $ 0.5625 $ 0.5625 $ 0.5625 $ 0.5625 $ 0.5625 $ 0.5625 $ 0.5625 $ 0.5625 Market Price $ Per Share (NYSE) High 23'/s 24 24'/s 25'/s 24'/s 24'I>> 24 23s/>>

Low 21'/z 21'/s 231/>> 23'/s 22 22'/z 22'/>> 217/s

$ 2.75 Series Dividends Paid Per Share $ 0.6875 $ 0.6875 $ 0.6875 $ 0.6875 $ 0.6875 $ 0.6875 $ 0.6875 S0.6875 Market Price S Per Share (NYSE) High 26'/z 27'/ 27 27'/z 27'/s 27 27%

Low 26 25'/z 26'/>> 26'/s 26'/>>- 26'/>> 26'/s MSE Midwest Stock Exchange OTC Over-the. Counter NYSE New York Stock Exchange Note The above bid and asked quotations represent prices between dealers and do not represent actual transactions.

Market quotations provided by National Quotation Bureau, Inc.

Dash indicates quotation not available.

28

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

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 INDIANA MICHlGAN POWER COMPANY'S PROJECTED CASH FLOW

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

($ Millions)

Actual Projected 1989 1990 Net income after taxes 137.1 136 Less'ividends paid 138.2 129 Retained earnings (1.1) 7 Adjustments:

Depreciation and amortization 150.5 152 Deferred Federal income taxes and investment tax credits 26.9 (21)

AFUDC (60.1) ( 3)

Total adjustments 117.3 128 Internal cash flow 116.2 135 Average quarterly cash flow 29.0 34 Average cash balances and short-term investments 58.7 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