ML17325B618

Indiana Michigan Power Co 1998 Annual Rept. Projected Cash Flow for 1999,included.With 990528 Ltr

ML17325B618
Person / Time
Site:	Cook
Issue date:	12/31/1998
From:	Powers R INDIANA MICHIGAN POWER CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:09090, AEP:NRC:9090, NUDOCS 9906030223
Download: ML17325B618 (58)

Text

CATEGORY'EGULATORY INFORMATION DISTRIBUTI ~ SYSTEM (RIDS)

ACCESSION NBR:9906030223 DOC.DATE: ~+M-FACIL:50-315 Donald C. Cook Nuclear Power Plant, Unit 1, Indiana M NOTARIZED: NO DOCKET 05000315 50-316 Donald C. Cook Nuclear Power Plant, Unit 2, Indiana M 05000316 AUTH.NANT AUTHOR AFFILIATION "

POWERS,R.P. Indiana Michigan Power Co.

RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"Indiana Michigan Power Co 19 ual Rept." Projected cash flow for 1999,included. With 9052 ltr.

DISTRIBUTION CODE: M004D COPIES RECEIVED:LTR ENCL SIZE:

TITLE: 50.71(b) Annual Financial Report NOTES: C'ECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL LPD3-1 LA 1 1 LPD3-1 PD 1 1 STANGiJ 1 1 R

INTERNAL. 1 1 NRR/DRIP NRR/DRIP/RGEB 1 1 EZTERNAL: NRC PDQ 1 1 D

U

'E WASTETH NOTE TO ALL "RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE TO HAVE YOUR NAME OR ORGANIZATION REMOVED FROM DISTRIBUTION LISTS OR REDUCE THE NUMBER OF COPIES RECEIVED BY YOU OR YOUR ORGANIZATION, CONTACT THE DOCUMENT CONTROL DESK (DCD) ON EXTENSION 415-2083 TOTAL NUMBER OF COPIES REQUIRED: LTTR 7 ENCL 7

Indiana Michigan~

Power Comp'any 500 Circle Drive ~

Buchanan, Ml 491071373 l&fblANA MCHIGAM lrOMfM May 28, 1999 AEP:NRC:09090 Docket Nos.: 50-315 50-316 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop 0-Pl-17 Washington, D. C. 20555-0001 Donald C. Cook Nuclear Plant Units 1 and 2 FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Gentlemen:

In accordance with 10 CFR 50.71(b), Indiana Michigan Power Company is submitting its 1998 annual report (attachment 1). Also in accordance with 10 CFR 140.21(e) a copy of Indiana Michigan Power Company's projected cash flow for 1999 ,(attachment 2) is being provided.

The NRC staff has been notified that this transmittal was delayed due to an administrative error in the Regulatory Affairs Department. This condition has been entered into our corrective action program to ensure timely resolution.

Sincerely, R. P. Powers Vice President

/mjg Attachments c: J. E. Dyer MDEQ DW & RPD NRC Resident Inspector R. Whale

'F906030223 981231 PDR ADQCK 05000315 I PDR

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ATTACHMENT 1 TO AEP:NRC:09090 INDIANA MICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1998

lie'limen@ IMIIchmgen Power Company 1998 Annual Report

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DIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES One Summit Square, P.o. Box 60, Fort Wayne, Indiana 46801 CONTENTS Background 2 Directors and Officers 3 Selected Consolidated Financial Data 4 Management's Discussion and Analysis of Results of Oper ations and Financial Condition . 5-19 Independent Auditors'eport 20 Consolidated Statements of Income . 21 Consolidated Balance Sheets . 22-23 Consolidated Statements of Cash Flows . 24 Consolidated Statements of Retained Earnings 25 Notes to Consolidated Financial Statements 26-45 Operating Statistics 46-47 Dividends and Price Ranges of Cumulative Preferred Stock 48

BACKGROUND l

INDIANA MICHIGAN POWER COMPANY (the Company) is engaged in the generation, sale,'urchase, transmission and distribution of electric power. The Company serves approximately 554,000 retail customers in northern and eastern Indiana and a portion of southwestern Michigan and sells and transmits power at wholesale to other electric utilities, municipalities, electric cooperatives and non-utility entities engaged in the wholesale power market. Approximately 83X of the Company's retail sales are in Indiana and 17K in Michigan. The principal industries served are primary metals, electrical and electronic machinery, transportation equipment, chemicals and allied products, fabricated metal products and rubber and "

miscellaneous plastic products.

The Company, which was organized under the laws of Indiana on February 21, 1925, is a of American Electric Power Company, Inc., a public utility holding company. The 'ubsidiary Company does business as American Electric Power (AEP) along with all of the parent's operating subsidiary companies in order to serve its customers more efficiently as one operating organization aligned by distinct business units. The Company's two wholly-owned subsidiaries, Blackhawk Coal Company and Price River Coal Company; were formerly engaged in coal-mining operations in Utah. Blackhawk Coal Company currently leases or subleases portions of its coal rights, land and related mining equipment to unaffiliated companies.

In addition, the Company has a river transportation division (RTD) that barges coal on the Ohio and Kanawha Rivers to AEP System generating plants. The RTD also provides some barging services to unaffiliated companies.

The Company owns and leases 4,435 megawatts (mw) of generating capacity which includes 2,295 mw of coal-fired generation and 2, 110 mw of nuclear generation. The Company owns the two unit Donald C. Cook Nuclear Plant located in Michigan. The generating plants and transmission facilities of the Company and certain other affiliated AEP System utility subsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission Equalization Agreement. Wholesale energy sales made by the Power Pool are allocated to the Company and the other Pool members.

The other AEP System Pool members are: Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company and Ohio Power Company. The Company is interconnected with two other affiliated companies, Kingsport Power Company and Wheeling Power Company that are not members of the Power Pool, and with numerous unaffiliated utilities through the AEP System. In addition, the Company is also directly interconnected with its affiliate, AEP Generating Company, and the following unaffiliated entities: Central Illinois Public Service Company, The Cincinnati Gas 5 Electric Company, Commonwealth Edison Company, Consumers Energy Corporation, Illinois Power Company, Indianapolis Power Im Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power and Light Company, as well as Indiana-Kentucky Electric Corporation (a subsidiary of Ohio Valley Electric Corporation, an affiliate that is not a member of the AEP System).

ANA MICHIGANPOWER COMPANY AND SUBSIDIARIES DIRECTORS Karl G. Boyd Henry W. Fayne (c) David B. Synowiec Coulter R. Boyle, III James A. Kobyra (d) Joseph H. Vipperman Gregory A. Clark William J. Lhota William E. Walters Peter J. DeNaria (a) Gerald P. Haloney (a) Earl H. Wittkamper William.N. O'Onofrio (b) James J. Harkowsky E. Linn Draper, Jr. Armando A. Pena (c)

E. Linn Draper Jr. John R. Sampson (i)

Chairman of the Board and Chief Executive Site Vice President, Donald C. Cook Officer Plant William J. Lhota Joseph H. Vipperman President and Chief Operating Officer Vice President A. Alan Blind (e) Leonard V. Assante (c)

Vice President, Nuclear Engineering Controller and Chief Accounting Officer Coulter R. Boyle, III John F. DiLorenzo, Jr.

Vice President Secretary Peter J. DeMaria (a) Elio Bafile Vice President and Controller Assistant Controller and Assistant Secretary Henry W. Fayne (c) Timothy P. Bowman Vice President Assistant Controller Eugene E. Fitzpatrick (f) William L. Scott Vice President Assistant Controller Gerald P. Haloney (a) John H. Adams, Jr. (b)

Vice President Assistant Secretary James J. Markowsky Thomas G. Berkemeyer (d)

Vice President Assistant Secretary Armando A. Pena (c) Maurice C. McIntyre Vice President, Treasurer and Chief Assistant Secretary Financial Officer Robert P. Powers (g) John B. Shinnock Vice President Assistant Secretary Michael W. Rencheck (h) Bruce H. Barber Vice President - Nuclear Engineering Assistant Treasurer Christopher J. Keklak Assistant Treasurer As of January I, 1999 the current dfrectors and offfcers of Indfana Mfchfgan'ower Company were empfoyees of Amer1can Electrfc Power Servfce Corporatfon w1th sfx exceptfons: Messrs. Boyd, Boyle, CIark, Mclntyre, IfaIters and Nfttkamper, who sere empIoyees of Indfana Mfchfgan PoNer Company.

(a) Resigned June 1, 1998 (d) Elected January 28, 1998 (g) Elected August 27, 1998 (b) Resigned January 28, 1998 (e) Resigned June 17, 1998 (h) Elected December 16, 1998 (c) Elected June 1, 1998 (f) Resigned Hay 1, 1998 (l) Elected January 15, 1998

r n d e ember 192Z 1RK (in thousands)

INCOME STATEMENTS DATA:

Operating Revenues $ 1,405,794 $ 1,339,232 $ 1,283,157 $ 1,251,309 Operating Expenses 3 78 4 4 Operating Income 1 7 ~ 7 7 Nonoperating Income (Loss)

Income Before Interest Charges 165,168 211,995 229,397 Interest Charges 6 5 5 Net Income 9, 8 1,7 157,15 111, P2 157,502 Preferred Stock Dividend Requirements Earnings Applicable to

~48 4 ~4221 Common Shock ~~84 ~4~4 M346.~47 ~29 ZR ~L44.~

(in t ousands)

BALANCE SHEETS DATA:

Electric Utility Plant $ 4,631,848 $ 4,514,497 $ 4,377,669 $ 4,319,564 $ 4,269,306 Accumulated Depreciation

~~4 Net and Plant Amortization Electric Utility Total Assets g 5~5

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~23M

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~6~66 Common Stock and Paid-in Capital 789,189 789,056 787,856 787,686 790,234 Retained Earnings Total Common 4

~~65 Shareholder's Equity a k44 ~3 aJK~I XL95RBZZ K.JR3 a M6 m Cumulative Preferred Stock:

Not Subject to Handatory Redemption $ 9,273 $ 9,435 $ 21,977 $ 52,000 $ 52,000 Subject to Mandatory Redemption (a) ~KJHE ~!SPRUE Total Cumulative Preferred Stock ~~JtK ~6322 ~Z.999 ~U GK Long-term Debt (a) XL1L'~~7 kl.~4~7 41JL44 ~4 S ~4~ ~L66 E~Z Obligations Under Capital Leases (a) 86 4 7 M39'~l PAL 2K 4 uL H Total Capitalization and Liabilities ~148 523. n.~.zm. ~892.~4 a Inc u sng portion due within one year.

I IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION This discussion includes service territory in northern and forward-looking statements within the eastern Indiana and a portion of meaning of Section 21E of the southwestern Michigan and conducts Securities Exchange Act of 1934. business as American Electric Power These 'orward-looking statements (AEP). The Company supplies electric reflect assumptions, and involve a power to the AEP System Power Pool number of risks and uncertainties. (AEP Power Pool) and shares the Among the factors that could cause revenues and costs of AEP Power Pool actual results to differ materially wholesale sales to utility systems from forward looking statements are: and power marketers. The Company also electric load and customer growth; sells wholesale power to abnormal weather conditions; municipalities and electric available sources and costs of fuels; cooperatives. As a member of the AEP availability of generating capacity; Power Pool and a signatory company to the speed and degree to which the AEP System Transmission competition is introduced to the Equalization Agreement, the Company's power generation business, the generation and transmission structure and timing of a competitive facilities are operated in market and its impact on energy conjunction with the facilities of prices or fixed rates; the ability to certain other affiliated utilities as recover stranded costs in connection an integrated utility system.

with possible deregulation of generation; new legislation and suts f ra in government regulations; the ability of the Company to successfully Although operating revenues control its costs; the economic increased $ 67 million or 5X in 1998 climate and growth in our service and $ 11 million or 1X in 1997, net territory; unforeseen events income decreased in both years. Net affecting the Company's nuclear plant income declined $ 50 million or 34K in which is on an extended safety 1998 due to increased purchased power related shutdown; unforeseen problems and maintenance expense related to an or failures related to Year 2000 extended outage of the Company's two readiness of computer software and unit Donald C. Cook Nuclear Plant hardware; inflationary trends; (Cook Plant) which was shutdown in electricity market prices; interest September 1997 and losses on certain rates; and other risks and unforeseen non-regulated energy trades outside events. This discussion contains a of the AEP Power Pool's traditional "Year 2000 Readiness Disclosure" marketing area. The 1997 decline of within the meaning of the Year 2000 $ 10 million or 7X resulted from Information and Readiness Disclosure increases in purchased power and Act. other operation expenses due in part to the nuclear plant outage.

Indiana Michigan Power Company (the Company) is a wholly-owned subsidiary of American Electric Power Company, Inc. (AEP Co., Inc.), a Operating revenues increased 5X public utility holding company. The in 1998 following a 1X increase in Company is engaged in the generation, 1997. The increases in operating purchase, sale, transmission and revenues in 1998 and 1997 can be distribution of electric power to attributed mainly to increased retail 554,000 retail customers in its revenues. The following analyzes the

changes in operating revenues: peak demand of all member companies as a basis for sharing revenues and Increase (Oecrease) m u costs. The result of this ol ars in Milli n calculation is each Company's member Retail:

~mon $ ~mn $ load ratio (MLR) which determines Residential $ 26.4 5 4.3 each Company's percentage share of Commercial 26.1 10.3 revenues or costs. During 1998 the ial Industr Other ~4 38.1 91.0 9.6 19.4 34.0 3.7 Company's MLR increased resulting in the Company being allocated a larger share of wholesale revenues and Wholesale (40.6)(11.2) (29.1) (7.4) from the expenses AEP Power Pool.

Transmission Miscellaneous Total ~6 13.4 83.2 27.6 5.0

~

~0 4.3 35.9 18.6 0.8 develop In 1997 management decided to business.

a power marketing and trading The power marketing and trading business is conducted by the Revenues from reta i 1 customers AEP Power Pool and its revenues and increased in 1998 due to the accrual expenses are allocated to AEP Power of revenues under fuel adjustment Pool members based on MLR.

clauses for the increased cost of replacement power and increased Wholesale revenues declined in fossil fuel usage necessitated by the 1998 due to a decline in sales to the extended outage of the Company's two AEP Power Pool reflecting the nuclear units and a 3X increase in unavailability of the nuclear units.

sales. The increase in retail The decline was partially offset by revenues in 1997 resulted from the the Company's share of increased acct'uals of revenues to be recovered power marketing sales and trading under power supply recovery activities. A decrease in sales to mechanisms. Under the retail the AEP Power Pool due mainly to the jurisdictional fuel clauses, revenues are accrued for the unrecovered cost outage of Cook Plant is'lso the primary reason for the decline in of fuel in both retail jurisdictions wholesale revenues in 1997.

and for replacement power costs in the Michigan jurisdiction until approved for billing.

Total operating expenses The Company as part of the AEP increased 10X in 1998 and 2X in 1997 System shares costs and benefits of primaiily due to an increase in power the System's generating facilities purchases. The changes in operating through the AEP Power Pool. The cost expenses were:

of the System's generating capacity Increase (Oecrease) is allocated among the AEP Power Pool

members, demands based and on their relative generating peak reserves

~mu ~ ~mn thiough the payment or receipt of Fuel 5(53.8) (23.8) $ (9.8) (4.2)

Purchased Power 133.3 80.9 26.1 18.8 capacity charges and credits. AEP Other OPeration 13.1 3.9 23.6 7.6 Power Pool members are also Maintenance 39.8 33.8 2.5 2.2 Oepreciation and compensated for the out-of-pocket Amortization 4.3 3.1 0.4 0.3 costs of energy delivered to the AEP Amortization of Reexport Power Pool and charged for energy Plant Unit 1 Phase-in Plan Oeferrals (11.9)(100.0) (3.8) (24.1) received from the AEP Power Pool. Taxes Other Than The AEP. Power Pool calculates each Company's prior twelve month Federal Income Taxes Federal Income Taxes Total

~)

~08.

2.6 4.1 (27.0)

9. 6

~)(8.8) (11.9)

(8.8) 2.1 peak demand relative to the total

I IANA MICHIGAIVPOWER COMPANY AND SUBSIDIARIES The decrease in fuel expense in nc me 1998 and 1997 reflects the decrease in nucle'ar generation as both nuclear The decline in nonoperating units were unavailable from September income is due to losses in 1998 from 1997 through the end of 1998. See non-regulated electricity trading Cook Nuclear Plant Shutdown discussed activities. These trading activities below. are for forward electricity sales and purchases outside of the AEP Power Purchased power expense Pool's traditional marketing area and increased significantly in 1998 and also include electricity derivatives 1997 due to increased purchases from such as options, swaps, etc. Open the AEP Power Pool and the Company's trades are marked-to-market and MLR share of increased purchases of recorded in nonoperating income.

electricity by the AEP Power Pool.

The purchases replace power usually ines u loo generated by the unavailable nuclear units and supply the electricity for The most significant factors the AEP Power Pool's marketing sales. affecting the Company's future earnings are the restart of the Cook The increases in other operation Plant units (discussed below under and maintenance expenses in 1998 were Cook Nuclear Plant Shutdown) and the due to expenditures to prepare the ability to recover costs as the nuclear units for restart. Other electric generating business becomes operation expense increased in 1997 more competitive. The introduction due to the effect of gains on the of competition and customer choice disposition of emission allowances for retail customers in the Company's recorded in 1996 and higher service territory has been slow and administrative and general costs and continues at a deliberate pace as uncollectible accounts receivable legislators and regulatory officials expenses. recognize the complexity of the issues. Federal legislation has been The recovery period for Rockport proposed to mandate competition and Plant Unit 1 costs deferred under customer choice at the retail level, rate phase-in plans in the Indiana and several states have introduced or and the Federal Energy Regulatory are considering similar legislation.

Commission (FERC) jurisdictions ended Certain states, including California, in 1997 causing the decrease in the instituted full customer choice in amortization of phase-in plan 1998. The Michigan Commission has deferrals. The deferred costs were started a program for certain amortized over a 10-year period utilities to phase-in to competition commensurate with their collection with the objective of providing full from customers. customer choice by 2002. The Company has begun discussions with the The decrease in taxes other than Michigan Commission and other federal income taxes in 1997 was due interested parties to formulate a to decreases in real and personal plan. The actions by the Michigan property taxes, Michigan single Commission were not mandated by business tax and Indiana supplemental legislation and are subject to a income tax. number of uncertainties and it is not presently possible to determine what Federal income taxes impact if any the resolution of these attributable to operations decreased matters will have on the operations in 1998 and 1997 due to decreases in of the Company. The Company's pre-tax operating income. Michigan jurisdiction accounts for 13X of total revenues. Indiana is

considering 1 egi sl ati ve ini ti ati ves rates charged to customers be cost-to move to customer choice, although based and provide for the recovery of the timing is uncertain. The Company deferred expenses over'uture supports customer choice and is accounting periods. In the event a proactively involved in discussions portion of the Company's business no at both the state and federal levels longer meets the requirements of SFAS regarding the best competitive market 71, SFAS 101 "Accounting for the structure and method to transition to Discontinuance of Application of a competitive marketplace. Statement 71" requires that net regulatory assets be written off for As the pricing of generation in that portion of the business. The the electric energy market evolves provisions of SFAS 71 and SFAS 101 from regulated cost-of-service never anticipated that deregulation ratemaking to market-based rates, would include an extended transition many complex issues must be resolved, period or that it could provide for including the recovery of stranded recovery of stranded costs during and costs. Stranded costs are those after the transition period. In 1997 costs above market that potentially the Financial Accounting Standards would not be recoverable in a Board's (FASB) Emerging Issues Task competitive market. At the wholesale Force (EITF) addressed such a level recovery of stranded costs situation with the consensus reached under certain conditions was on issue 97-4 that requires the addressed by the FERC when it application of SFAS 71 to a segment established rules for open of a regulated electric utility cease transmission access and competition when that segment is subject to a in the wholesale markets. However, legislatively approved plan for the issue of stranded cost is competition or an enabling rate order unresolved at the retail level where is issued containing sufficient it is much larger than it is at the detail for the utility to reasonably wholesale level. The amount of determine what the plan would entail.

stranded cost the Company could The EITF indicated that the cessation experience depends on the timing and of application of SFAS 71 would extent to which competition is require that regulatory assets and introduced to its generation business impaired plant be written off unless and the future market prices of they are recoverable in future rates.

electricity. The recovery of stranded cost is dependent on the Although certain FERC orders terms of future legislation and provide for competition in the firm related regulatory proceedings. wholesale market, that, market is a relatively small part of our business Under the pr ovisions of and most of our firm wholesale sales Statement of Financial Accounting are still under cost-of-service Standards (SFAS) 71 "Accounting for contracts. As a result, the the Effects of Certain Types of Company's generation business is Regulation," regulatory assets still cost-based regulated and should (deferred expenses) and regulatory remain so for the near future. We liabilities (deferred revenues) are believe that enabling state included in the consolidated balance legislation should provide for the sheets of regulated utilities in recovery of any generation-related accordance with regulatory actions to net regulatory assets and other match expenses and revenues with reasonable stranded costs from cost-based rates in the same impaired generating assets. However, accounting period. In order to if in the future the Company's maintain net regulatory assets on the generation business were to no longer balance sheet, SFAS 71 requires that be cost-based regulated and if it

IN IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES were not possible to demonstrate believes that it has a meritorious probability of recovery of resultant position and will vigorously pursue stranded'osts including regulatory .this lawsuit. In the event the assets, results of operations, cash resolution of this matter is flows and financial condition would unfavorable, it will have a material be adversely affected. adverse impact on results of operations and cash flows.

w d if n ra The Company is involved in a number of other legal proceedings and The Internal Revenue Service claims. While we are unable to (IRS) agents auditing the AEP predict the outcome of such System's consolidated federal income litigation, it is not expected that tax returns for the years 1991 to the ultimate resolution of these 1993 requested a ruling from their matters will have a material adverse National Office that certain interest effect on the results of operations, deductions claimed by the Company cash flows and/or financial relating to AEP's corporate owned condition.

life insurance (COLI) program should not be allowed. As a result of a suit filed by the Company in United mrvmn States (US) District Court (discussed below) this request for ruling was Efforts continue to reduce the withdrawn by the IRS agents. cost of products and services in Adjustments have been or will be order to maintain competitiveness.

proposed by the IRS disallowing COLI The accounting department completed interest deductions for taxable years its consolidation of operations and 1991-96. A disallowance of the COLI the marketing department completed interest deductions through December its reorganization in 1998 producing 31, 1998 would reduce earnings by cost reductions. In 1998 the Company approximately $ 66 million (including reviewed its staffing levels for interest). The Company has made no power generation and energy delivery provision for any possible adverse and developed plans to reduce staff earnings impact from this matter. in 1999. The cost of staff reductions planned for 1999 was In 1998 the Company made provided for in the fourth quarter of payments of taxes and interest 1998. Although cost savings are attributable to COLI interest expected to result from the power deductions for taxable years 1991-97 generation and energy delivery to avoid the potential assessment by reorganizations, the Company the IRS of any additional above continues to incur expenses related market rate interest on the contested to investments in marketing and amount. The payments to the IRS are customer services and the included on the balance sheet in r eengineering and improvement of other property and investments business processes.

pending the resolution of this matter. The Company will seek During 1998, the Company refund, either administratively or completed installation of a new through litigation, of all amounts unified customer service system which paid plus interest. In order to is designed to support customer resolve this issue without further requests for service, billings, delay, on March 24, 1998, the Company accounts receivable, credit and filed suit against the US in the US collection functions. On January 1, District Court for the Southern 1999, the Company's new financial District of Ohio. Management data base and PeopleSoft client

server accounting and purchasing for the District of Columbia Circuit software became operational. The requesting, among other things, that move to client server business the court order DOE to meet .its software and related online data obligations under the law. The court bases will empower employees to ordered the parties to proceed with maximize the benefits of their contractual remedies but declined to personal computers and will position order DOE to begin accepting SNF for them to better access the power of disposal. DOE estimates its planned the Internet and other new site for the nuclear waste will not technologies. be ready until 2010. In June 1998, the Company filed a complaint in the r n N l r F 1 US Court of Federal Claims seeking damages in excess of $ 150 million due to the DOE's partial material breach The Company, as the owner of the of its unconditional contractual Cook Plant, like other nuclear power deadline to begin disposing of SNF plant owners, has a significant generated by the Cook Plant. Similar future financial commitment to safely lawsuits have been filed by other dispose of spent nuclear fuel (SNF) utilities. As long as the delay in and decommission and decontaminate the availability of a government the plant. The Nuclear Waste Policy approved storage repository for SNF Act of 1982 established federal continues, the cost of both temporary responsibility for the permanent off- and permanent storage will increase.

site disposal of SNF and high-level radioactive waste. By law we The cost to decommission the participate in the Department of Cook Plant is affected by both Energy's (DOE) SNF disposal program Nuclear Regulatory Commission (NRC) which is described in Note 3 of the regulations and the delayed SNF Notes to Consolidated Financial disposal program. Studies completed Statements. Since 1983 we have in 1997 estimate the cost to de-collected $ 272 million from customers commission the Cook Plant ranges from for the disposal of nuclear fuel $ 700 million to $ 1,152 million in consumed at the Cook Plant. Of these 1997 dollars. This estimate could funds, $ 115 million has been escalate due to continued uncertainty deposited in external trust funds to in the SNF disposal program and the provide for the future disposal of length of time that SNF may need to SNF and $ 157 million has been be stored at the plant site.

remitted to the DOE. Under the External trust funds have been provisions of the Nuclear Waste established and funded with amounts Policy Act, collections from collected from customers to customers are to provide the DOE with decommission the plant. At December money to build a repository for SNF. 31, 1998, the total decommissioning However, in December 1996, the DOE trust fund balance was $ 443 million notified the Company that it would be which includes earnings on the trust unable to begin accepting SNF by the investments. We will work with January 1998 deadline required by regulators and customers to recover law. the remaining estimated cost of decommissioning the Cook Plant.

As a result of DOE's failure to However, future results of make sufficient progress toward a operations, cash flows and possibly permanent repository or otherwise financial condition would be assume responsibility for SNF, the adversely affected if the cost of SNF Company along with a number of disposal and decommissioning continue unaffiliated utilities and states to incr ease and cannot be recovered filed suit in the US Court of Appeals from customers.

10

I DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES existing nuclear generation management and staff with personnel Manhgement shut down both units experienced in restarting of the Cook Plant in September 1997 unaffiliated companies'uclear due to questions, which arose during plants during NRC supervised extended a NRC architect engineer design outages.

inspection, regarding the operability of certain safety systems. The NRC The costs incurred in 1997 and issued a Confirmatory Action Letter 1998 for restart of the Cook units in September 1997 requiring the were $6 million and $ 78 million, Company to address the issues respectively, and were recorded as identified in the letter. We are operation and maintenance expense.

working with the NRC to resolve the Reductions in other operation and remaining open issue in the letter. maintenance expenses partially offset these costs. Currently incremental In April 1998 the NRC notified restart expenses are approximately the Company that it had convened a $ 12 million a month.

Restart Panel for Cook Plant. A list of required restart activities was In July 1998 the Company provided by the NRC in July 1998 and received an "adverse trend letter" in October the NRC expanded the list. from the NRC indicating that NRC In order to identify and resolve the senior managers determined that there issues necessary to restart the Cook had been a slow decline in units, the Company is and will be performance at the Cook Plant during meeting with the Panel on a regular the 18 month period preceding the basis, until the units are returned letter. The letter indicated that to service. the NRC will closely monitor efforts to address issues at Cook Plant In Januar y 1999 we announced through additional inspection that we will conduct additional activities. In October 1998 the NRC engineering reviews at the Cook Plant issued the Company a Notice of that will delay restart of the units. Violation and proposed a $ 500,000 Previously, the units were scheduled civil penalty for alleged violations to return to service at the end of at the Cook Plant discovered during the first and second quarters of five inspections conducted between 1999. The decision to delay restart August 1997 and April 1998. The resulted from internal assessments penalty was paid.

that indicated a need to conduct expanded system readiness reviews. A The cost of electricity supplied new restart schedule will be to retail customers rose due to the developed based on the results of the outage of the two units since higher expanded reviews and should be cost coal-fired generation and coal available in June 1999. When based purchased power were maintenance and other activities substituted for low cost nuclear required for restart are complete, generation. The Indiana and Michigan the Company will seek concurrence retail jurisdictional fuel cost from the NRC to return the Cook Plant recovery mechanisms permit the to service. Until these additional recovery, subject to regulatory reviews are completed, management is commission review and approval, of unable to determine when the units changes in fuel costs including the will be returned to service. fuel component of purchased power in the Indiana jurisdiction and changes One of the steps the Company has in replacement power in the Michigan taken toward expediting the restart jurisdiction. Under these fuel cost of the Cook units is to augment its recovery mechanisms, retail rates 11

contain a fuel cost adjustment factor to $ 150 million of incremental that reflects estimated fuel costs operation and maintenance restart for the period during which the costs for the Cook Plant above .the factor will be in effect subject to base rate level incurred during 1999; reconciliation to actual fuel costs amortization of the fuel recoveries in a future proceeding. When actual and restart cost deferral s over a fuel costs exceed the estimated costs five-year period ending December 31, reflected in the billing factor a 2003; a freeze in base rates though regulatory asset is recorded and December 31, 2003; and a cap on fuel revenues are accrued. Therefore, a recovery charges through Harch 1, regulatory asset has been recorded 2004. The $ 55 million credit will be and revenues accrued in anticipation refunded through customer's bills of the future reconciliation and during the months of July, August and billing under the fuel cost recovery September 1999. If the IURC does not mechanisms of the higher fuel costs approve the settlement, the issue of to replace Cook energy during the recovery of replacement energy costs extended outage. At December 31, would be resolved through regulatory 1998, the regulatory asset was $ 65 hearings.

million.

Unless the costs of the extended The Indiana Utility Regul ator y outage and restart efforts are Commi ssi on ( IURC) approved, subject recovered from customers, there would to future reconciliation or refund, be a material adverse effect on agreements authorizing the Company, results of operations, cash flows, during the billing months of July and possibly financial condition.

1998 through Harch 1999, to include in rates a fuel cost adjustment v' l n r factor less than that requested. The agreements provide the parties to the We take great pride in our proceedings with the opportunity to efforts to economically produce and conduct discovery regarding certain deliver electricity while minimizing issues that were raised in the the impact on the environment. The proceedings, including the Company has spent hundreds of appropriateness of the recovery of millions of dollars to equip our replacement energy cost due to the facilities with the latest economical extended Cook Plant outage, in clean air and water technologies and anticipation of resolving the issues to research new technologies. We in a future fuel cost adjustment intend to continue in a leadership proceeding. role fostering economically prudent efforts to protect and preserve the On Harch 16, 1999 a settlement environment.

agreement was filed with the IURC resolving all matters related to the By-products from the generation reasonableness of fuel costs and all of electricity include materials such outage issues during an extended as ash, slag, sludge, low-level outage of the Cook Plant. The radioactive waste and SNF. Coal settlement agreement, which is combustion by-products are typically subject to IURC approval, provides disposed of or treated in captive for, among other things, a credit of disposal facilities or are

$ 55 million to Indiana retail beneficially utilized. In addition, customers; authorization to defer any our generating plants and trans-unrecovered fuel revenues accrued mission and distribution facilities between September 9, 1997 and have used asbestos, polychlorinated December 31, 1999 including the $ 55 biphenyls (PCBs) and other hazardous million; authorization to defer up and nonhazardous materials. The 12

t INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Company is currently incurring costs utility sources of approximately 85K to safely dispose of such substances. below 1990 emission levels by the Additional costs could be incurred to year 2003. On October 30, 1998, a comply with new laws and regulations number of utilities, including the if enacted. Company and the other operating companies of the AEP System, filed a The Comprehensive Environmental petition in the US Court of Appeals Response, Compensation and Liability for the District of Columbia Circuit Act (Superfund) addresses clean-up of seeking a review of the final rules.

hazardous substances at disposal sites and authorized the US Should the states fail to adopt Environmental Protection Agency the required revisions to their SIPs (Federal EPA) to administer the within one year of the date the final clean-up programs. As of year-end rules were signed (September 24, 1998, the Company is currently 1999), Federal EPA has proposed to involved in litigation with respect implement a federal plan to to one site overseen by the Federal accomplish the NOx reductions.

EPA, and has been named by the Federal EPA also proposed the Federal EPA as a potentially approval of portions of petitions responsible party (PRP) for two other filed by eight northeastern states sites. There is one additional site that would result in imposition of for which the Company has received an NOx emission reductions on utility information request which could lead and industrial sources in upwind to PRP designation. Historically, midwestern states. These reductions the Company's liability has been are substantially the same as those resolved for a number of sites with required by the final NOx rules and no significant effect on results of could be adopted by Federal EPA in operations and present estimates do the event the states fail to not anticipate material cleanup costs implement SIPs in accordance with the for identified sites for which we final rules.

have been declared a PRP. However, if for reasons not currently that Preliminary estimates could result indicate in identified significant cleanup costs compliance are incurred, results of operations, required capital expenditures of cash flows and possibly financial approximately $ 169 million.

condition would be adversely affected Compliance costs cannot be estimated unless the costs can be recovered with certainty and the actual costs from customers. incurred to comply could be significantly different from this On September 24, 1998, the preliminary estimate depending upon administrator of Federal EPA signed the compliance alternatives selected final rules which require reductions to achieve reductions in NOx in nitrogen oxides (NOx) emissions in emissions. Unless such costs are 22 eastern states, including the recovered from customers, they would states in which the generating plants have a material adverse effect on of the Company and its affiliates in results of operations, cash flows and the AEP System are located. The possibly financial conditions implementation of the final rules would be achieved through the At the Third Conference of the revision of state implementation Parties to the United Nations plans (SIPs) by September 1999. SIPs Framework Convention on Climate are a procedural method used by each Change held in Kyoto, Japan in state to comply with Federal EPA December 1997 more than 160 rules. The final rules anticipate countries, including the US, the imposition of a NOx reduction on negotiated a treaty requiring 13

legally-binding reductions in ranging from 7X to 7.8X. Our senior emissions of greenhouse gases, secured debt/first mortgage bond chiefly carbon dioxide, which many ratings are: Moody's, Baal; Standard scientists believe are contributing & Poor's, A-; and Fitch, BBB+.

to global climate change. The treaty, which requires the advice and Gross plant and property consent of the US Senate for additions were $ 159 million in 1998 ratification, would require the US to and $ 235 million in 1997. Management reduce greenhouse gas emissions seven estimates construction expenditures percent below 1990 levels in the for the next three years to be $ 366 year s 2008-2012. Although the US has million which includes the agreed to the treaty and signed it on replacement of the Cook Plant Unit 1 November 12, 1998, President Clinton steam generators. The funds for has indicated that he will not submit construction of new facilities and the treaty to the Senate for improvement of existing facilities consideration until it contains can come from a combination of requirements for "meaningful internally generated funds, short-participation by key developing term and long-term borrowings, countries" and the rules, procedures, preferred stock issuances and methodology and guidelines of the investments in common equity by the treaty's market-based policy Company's parent, American Electric instruments, joint implementation Power Company, Inc. (AEP Co., Inc.)

programs and compliance enforcement However, all of the construction provisions have been negotiated. At expenditures for the next three years the Fourth Conference of the Parties, are expected to be financed with held in Buenos Aires, Argentina, in internally generated funds.

November 1998, the parties agreed to a work plan to complete negotiations When necessary the Company on outstanding issues with a view generally issues short-term debt to toward approving them at the Sixth provide for interim financing of Confer ence of the Parties to be held capital expenditures that exceed in December 2000. We will continue internally generated funds. At to work with the Administration and December 31, 1998, $ 763 million of Congress to monitor the development unused short-term lines of credit of public policy on this issue. shared with other AEP System companies were available. Short-term If the Kyoto treaty is approved debt borrowings are limited by by Congress, the costs to comply with provisions of the Public Utility the emission reductions required by Holding Company Act of 1935 to $ 300 the treaty are expected to be million. Generally periodic substantial and would have a material reductions of outstanding short-term adverse impact on results of debt are made through issuances of operations, cash flows and possibly long-term debt and additional capital financial condition if not recovered contributions by the parent company.

from customers.

The Company's earnings coverage presently exceeds all minimum coverage requirements for the The Company issued $ 175 million issuance of mortgage bonds and principal amount of long-term preferred stock. The minimum coverage obligations in 1998 at interest rates ratios are 2.0 for mortgage bonds and ranging from 6.45K to 7.6X. The 1.5 for preferred stock. At December principal amount of long-term debt 31, 1998, the mortgage bond and r etir ements, including maturiti es, preferred stock coverage ratios were totaled $ 55 million at interest rates 6.39 and 2.08, respectively.

I DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES The Company i s committed under the Company's results of operations, unit power agreements to purchase all cash flows or financial condition.

of. an a'ffiliate's share, 50K of the 2,600 megawatt (mw) Rockport Plant The Company is exposed to capacity, unless it is sold to other changes in interest rates primarily utilities. The affiliate has a long- due to short-term and long-term term unit power agreement for the borrowings to fund its business sale of 455 mw to an unaffiliated operations. The debt portfolio has utility. Revenues received under both fixed and variable interest this agreement (which expires at the rates with terms from one day to end of 1999) were $ 70 million in forty years and an average duration 1998. An agreement between the of six years at December 31, 1998.

affiliate which owns Rockport Plant The Company measures interest rate and another affiliate provides for market risk exposure utilizing a VaR the sale of 390 mw of capacity to model. The model is based on the that affiliate through 2004. Monte Carlo method of simulated price movements with a 95X confidence level and a one year holding period. The volatilities and correlations are The Company has certain market based on three years of monthly risks inherent in its business prices. The risk of potential loss activities from changes in in fair value attributable to the electricity commodity prices and Company's exposure to interest rates, interest rates. The trading of primarily related to long-term debt electricity and related financial with fixed interest rates, was $ 102 derivative instruments through the million at December 31, 1998. The AEP Power Pool on the Company's Company would not expect to liquidate behalf exposes the Company to market its entire debt portfolio in a one risk. Market risk represents the year holding periods Therefore, a risk of loss that may impact the near term change in interest rates Company due to adverse changes in should not materially affect results electricity commodity market prices of operations or the consolidated and rates. In 1998 the AEP Power financial position of the Company.

Pool substantially increased the Also since the Company's rates are volume of its wholesale power cost-based regulated, the risk of marketing and trading activities. interest rate changes on debt used to Various policies and procedures have finance regulated operations is been established to manage market mitigated.

risk exposures including the use of a risk measurement model utilizing Inflation affects the Company's Value at Risk (VaR). Throughout the cost of replacing utility plant and year ending December 31, 1998, the the cost of operating and maintaining Company's share of the highest, its plant. The rate-making process lowest and average quarterly VaR in generally -limits our recovery to the the wholesale trading portfolio was historical cost of assets resulting less than $ 2 million at a 95K in economic losses when the effects confidence level with a holding of inflation are not recovered from period of three business days. The customers on a timely basis.

AEP Power Pool uses the variance- However, economic gains that result covariance method for calculating VaR from the repayment of long-term debt based on three months of daily with inflated dollars partly offset prices. Based on this VaR analysis, such losses.

at December 31, 1998 a near term change in commodity prices is not expected to have a material effect on 15

readiness program. HERC then publicly reports summary information to the DOE regarding the Year 2000 readiness of electric utilities. In On or about midnight on Oecember 1999 AEP plans to participate in two 31, 1999, digital computing systems NERC-sponsored coordinated electric may begin to produce erroneous industry Year 2000 readiness drills.

results or fail, unless these systems are modified or replaced, because The second NERC report, dated such systems may be programmed January 11, 1999 and entitled:

incorrectly and interpret the date of re ari h 1 ctr' r m January 1, 2000 as being January 1st of the year 1900 or another incorrect date. In addition, certain systems or Fo t ar r may fail to detect that the year 2000 states that: "With more than 44X of is a leap year. Problems can also mi ssi on cri ti cal components tested arise earlier than January 1, 2000, through November 30, 1998, findings as dates in the next millennium are continue to indicate that transition entered into non-Year 2000 ready through critical Year 2000 (Y2K) programs. rollover dates is expected to have minimal impact ,on electric system Readiness Program - Internally, operations in North America." The the Company, through the AEP System, Company continues to set a target is modifying or replacing its date of June 30, 1999 for having all computer hardware and software mission critical and high priority programs to minimize Year systems and components Y2K ready.

2000-related failures and repair such failures if they occur. This Through the El ectri c Power includes both information technology Research Institute, an electric systems (IT), which are mainframe and industry-wide effort has been client server applications, and established to deal with Year 2000 embedded logic systems (non-IT), such problems affecting embedded systems.

as process controls fo'r energy Under this effort, participating production and delivery. Externally, utilities are working together to the problem is being addressed with assess specific vendors'ystem entities that interact with the problems and test plans.

Company, including suppliers, customers, creditors, financial The state regulatory commissions service organizations and other in the Company's service territory parties essential to the Company's are also reviewing the Year 2000 operations. In the course of the readiness of the Company.

external evaluation, the Company has sought written assurances from third Company's State of Readiness parties regarding their state of Year Wor k has been prioritized in 2000 readiness. accordance with business risk. The highest priority has been assigned to Another issue we are addressing acti vi ti es that potenti al ly affect is the impact of electric power grid safety, the physical generation and problems that may occur outside of delivery of energy, and our transmission system. The communications; followed by back Company, along with other electric office activities such as customer utilities in North America, regularly service/billing, regulatory submits information to the North reporting, internal reporting and American Electric Reliability Council administrative activities (e.g.

(NERC) as part of NERC's Year 2000 payroll, procurement, accounts 16

INDIANAMICHIGANPOWER COMPANY AND SUBSIDlARIES payable); and finally, those activities that would cause inconvenience or productivity loss in normal business operations.

The following chart shows our progress toward becoming ready for the Year 2000 as of December 31, 1998:

IT SYSTEMS HOH- IT SYSTEMS COMPLETIOH COMP LETIOH DATE/ESTIMATED PERCEHT DATE/ESTIMATED PERCEHT Y 0 P PH COMPLETIOH DATE COMPLETE COMPLETIOH DATE COMPLETE Launch: In1tiation of 2/24/1998 100$ 5/31/1998 100$

the Year 2000 activ1ties within the organization.

Establishment of organizational structure, personnel assignments and budget for the workgroup.

Cont1nuous management update and awareness program.

Inventory and Assessment:

Identifying all Company 7/31/1998 100K 2/15/1999 99$

computer systems that could be affected by the millennium change.

Prioritize repair efforts based upon criticality to maintaining ongoing operations.

Remediation/Testing: The process of mod1fying, 6/30/1999 Mainframe: 6/30/1999 37K replacing or retir1ng those m1ss1on 70K cr1tical and high prior1ty d1gital-based system w1th problems processing dates past the Client Year 2000. Testing these Server:

systems to ensure that after 18$

modif1cat1ons have been implemented correct date processing occurs and full functionality has been maintained.

Costs to Address the Company 's Risks of the Company's Year ZOOO Year ZOOO Issues - Through December Issues - The applications posing the 31, 1998, the Company has spent $ 4 greatest business risk to the million on the Year 2000 project and, Company's operations should they estimates spending an additional $ 6 experience Y2K problems are:

million to $ 9 million to achieve Year 2000 readiness. Most Year 2000 costs , Automated power generation, are for software modifications, IT transmission and distribution consultants and salaries and are systems expensed; however, in certain cases Telecommunications systems the Company has acquired hardware Energy trading systems that was capitalized. The Company Time-in-use, demand and remote intends to fund these expenditures metering systems for commercial through internal sources. Although and industrial customers and significant, the cost of becoming Work management and billing Year 2000 compliant is not expected systems.

to have a material impact on the Company's results of operations, cash flows or financial condition.

17

The potential problems related Nw c nin to erroneous processing by, or failure of, these systems are: In 1997 the FASB issued SFAS 130 "Reporting Comprehensive Income" and Power service interruptions to SFAS 131 "Disclosures About Segments customers of an Enterprise and Related Interrupted revenue data Information." SFAS 130 establishes gathering and collection the standards for reporting and Poor customer relations displaying components of resulting from delayed billing "comprehensive income," which is the and settlement. total of net income and all transactions not included in net In addition, although as income affecting equity except those discussed relationships with third with shareholders. The Company parties, such as suppliers, customers adopted SFAS 130 in the first quarter and other electric utilities, are of 1998. For 1998 there were no being monitored, these third parties material differences between net nonetheless represent a risk that income and comprehensive income.

cannot be assessed with precision or controlled with certainty. SFAS 131 initiates standards for annual and interim financial Due to the complexity of the statements to report operating problem and the interdependent nature segments of a business for which of computer systems, if our separate financial information is corrective actions, and/or the available and regularly evaluated by actions of others not affiliated with the chief operating decision maker in the AEP System, fail for critical allocating resources and reviewing applications, Year 2000-related performance. Information about issues may materially adversely products and services and geographic affect the Company. areas is to be reported at an enterprise-level instead of by Company 's Contingency Plans - To segment. SFAS 131 was required to be address possible failures of electric adopted by the Company for the year generation and delivery of electrical ended December 31, 1998 with energy due to Year 2000 related restatement of prior period failures, we have established a draft comparative information. Adoption of Year 2000 contingency plan and SFAS 131 did not have any effect on submitted it to the East Central Area results of operations, cash flows or Reliability Council in December 1998 financial condition.

as part of NERC's review of regional and individual electric utility In the first quarter of 1998 the contingency plans in 1999. NERC's Company adopted the American target date is June 1999 for the Institute of Certified Public completion of this contingency plan. Accountants'AICPA) Statement of In addition, the Company intends to Position (SOP) 98-1, "Accounting for establish contingency plans for its the Costs of Computer Software business units to address Developed or Obtained for Internal alternatives if Year 2000 related Use". The SOP requires the failures occur. Contingency plans capitalization and amortization of will be developed by the end of 1999. certain costs of acquiring or The Company's plans build upon the developing internal use computer disaster recovery, system software. Previously the Company restoration, and contingency planning expensed all software acquisition and that we have had in place. development costs. The SOP had to be 18

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES adopted at the beginning of a fiscal The FASB i ssued SFAS 133 year with no restatement or "Accounting for Deri vati ve retroactive adjustment of prior Instruments and Hedging Activities" periods. The adoption of the SOP in June 1998. SFAS 133 establishes effective January 1, 1998 did not accounting and reporting standards have a material effect on results of for derivative instruments. It operations, cash flows or financial requires that all derivatives be condition. recognized as either an asset or a liability and measured at fair value In February 1998, the FASB in the financial statements. If issued SFAS 132 certain conditions are met a about Pensions "Employers'isclosure and Other derivative may be designated as a Postretirement Benefits" which hedge of possible changes in fair revised employers'isclosures about value of an asset, liability or firm pensions and other postretirement commitment; variable cash flows of benefit plans and suggested that the forecasted transactions; or foreign disclosure be combined. It did not currency exposure. The change the measurement or recognition accounting/reporting for changes in a requirements for postretirement derivative's fair value (gains and benefit accounting. The adoption of losses) depend on the intended use SFAS 132 did not have an effect on and resulting designation of the results of operations, cash flows or derivative. Management is currently financial condition. studying the provisions of SFAS 133 to determine the impact, of its EITF 98-10 "Accounting for adoption on January 1, 2000, on Contracts Involved in Energy Trading results of operations, cash flows and and Risk Management Act.ivities" was financial condition.

issued in November 1998 to address the application of mark-to-market In April 1998 the AICPA issued accounting for energy trading SOP 98-5 "Reporting on the Costs of contracts. Under the provisions of Start-up Activities". The SOP this standard, which must be adopted clarifies the accounting and by the Company in January , 1999, reporting for one time start-up energy trading contracts can no activities and organization costs, longer be accounted for on a requiring that they be expensed as settlement basis. Instead they are incurred. The adoption of this to be marked-to-market. Initial standard in January 1999 is not adoption of EITF 98-10 is not expected to have a material effect on expected to have a significant impact results of operations, cash flows or on results of operations, cash flows, financial condition.

or financial condition.

19

INDEPENDENT AUDITORS'EPORT To the Shareholders and Board of Directors of Indiana Hichigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Hichigan Power Company and its subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well- as evaluating the overall financial statement presentation.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Hichigan Power Company and its subsidiaries as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP Columbus, Ohio February 23, 1999 (Harch 16, 1999 as to Note 4) 20

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Y r n d mbr

~7 (in thousands)

OPERATING REVENUES ~8~4 ~XhZR ~K~ 44>

.OPERATING EXPENSES:

Fuel 172,592 226,402 236,237 Purchased Power 298,046 164,775 138,687 Other Operation 347,207 334,115 310,513 Maintenance 157,593 117,780 115,300 Depreciation and Amortization 145,112 140,812 140,437 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 11,871 15,644 Taxes Other Than Federal Federal Income Taxes Income Taxes Total Operating Expenses 67,592

~~V. ~ 64,945 44 73,729 22 'RR; OPERATING INCOME NONOPERATING INCOME (LOSS)

INCOME BEFORE INTEREST CHARGES

~)

166,007 165,168 207,788 4 4 212,203

~7 220,417 223,146 INTEREST CHARGES NET INCOME 96,628 146,740 157,153 PREFERRED STOCK DIVIDEND REQUIREMENTS ~44 MLK1 EARNINGS APPLICABLE TO COMMON STOCK ~~84 ~4 4 ~144 4~

See Notes to Consolidated Financial Statements.

21

Consolidated Balance Sheets 1RRR ~97 (in thousands)

ASSETS ELECTRIC UTILITY PLANT:

Production $ 2,556,732 $ 2,545,484-Transmission 913,252 908,736 Distribution 768,803 737,902 General (including nuclear fuel)

Construction Work in Progress Total Electric Utility Plant

~K 236,650 411 4,631,848

~5 233,888, 48Z 4,514,497 Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT

~EL'.

55 43 ~4~56 NUCLEAR DECOHHISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS OTHER PROPERTY AND INVESTHENTS CURRENT ASSETS:

Cash and Cash Equivalents 12,465 5,860 Accounts Receivable:

Customers 94,502 107,087 Affiliated Companies 19,528 15,662 Hiscellaneous 18,743 14,561 Allowance for Uncollectible Accounts (2,027) (1,188)

Fuel - at average cost 20,857 17,182 Haterials and Supplies - at average cost 78,009 78,701 Accrued Utility Revenues Prepayments and Other TOTAL CURRENT ASSETS 37 277

~48 30,521 REGULATORY ASSETS ~4M 4M DEFERRED CHARGES TOTAL ~6L2.'5 See A'otes to Consolidated Financial Statements.

22

IAhfA MICHIGANPOWER COMPANY AND SUBSIDIARIES 192R '99Zmber 3 (in thousands)

CAPITALIZATION AND LIABILITIES CAP ITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares $ 56,584 $ 56,584 Paid-in Capital Retained Earnings Total Common Shareholder's Equity 732,605

~~~5~4 1,042,343

~78 732,472 1,067,870 4

Cumulative Preferred Stock:

Not Subject to Mandatory Redemption 9,273 9,435 Subject to Mandatory Redemption 68,445 68,445 Long-term Debt TOTAL CAPITALIZATION

~4

~~JJK9.

~~4 OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning Other TOTAL OTHER NONCURRENT LIABILITIES 445,934

~~2

~~36 381,016 CURRENT LIABILITIES:

Long-term Debt Due Within One Year 35,000 35,000 Short-term Debt 108,700 119,600 Accounts Payable - General 53,187 36,729 Accounts Payable - Affiliated Companies 37,647 31,665 Taxes Accrued 35,161 46,850 Interest Accrued 15,279 15,741 Obligations Under Capital Leases 9,667 34,033 Other TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES 'i2~E DEFERRED INVESTMENT TAX CREDITS 4 DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS 4~)

COMMITMENTS AND CONTINGENCIES (Note 3)

TOTAL ~4~41 'Q3.

See Notes to Consolidated Financial Statement's.

23

Consolidated Statements of Cash Flows 12RZ (in thousands)

OPERATING, ACTIVITIES:

Net Income '

$ 96,628 146,740 $ 157,153 Adjustments for Noncash Items:

Depreciation and Amortization 149,209 148,630 148,123 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 11,871 15,644 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) 14,142 (15,967) 7,662 Deferred Federal Income Taxes 17,905 3,922 (24,687)

Deferred Investment Tax Credits (8,266) (8,428) (8,729)

Over (Under)-recovery of Fuel and Purchased Power (46,846) (22,812) 12,477 Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net) 5,376 (10,456) (10,235)

Fuel, Materials and Supplies (2,983) 5,168 903 Accrued Utility Revenues (6,756) 7,774 5,642 Accounts Payable 22,440 6,502 1,186 Taxes Accrued (11,689) (18,550) (6,296)

Payment of Disputed Tax and Interest Related to COLI Other (net)

Net Cash Flows From Operating Activi.ties (53,628)

~~7)

~~2K'M.

~57 ~45 )

INVESTING ACTIVITIES:

Construction Expenditures (147,627) (122,360) (95,046)

Proceeds from Sales of Property and Other ~44 ~26.

Net Cash Flows Used For Investing Activities ~4~2) ~~44) ~>2 U2)

FINANCING ACTIVITIES:

Issuance of Long-term Debt 170,675 47,728 38,579 Retirement of Cumulative Preferred Stock (120) (78,877) (30,568)

Retirement of Long-term Debt (55,000) (50,000) (46,091)

Change in Short-term Debt (net) (10,900) 76,100 (46,475)

Dividends Paid on Common Stock (117,464) (131,260)

Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities

~4~) r~r54 ) Upp~4

)

(112,508)

~LQR)

~L Kl) ~

Net Increase (Decrease) in Cash and Cash Equivalents 6,605 (2,373) (5,490) .

Cash and Cash Equivalents January 1 Cash and Cash Equivalents December 31 5JKG See Notes to Consol idated Financial Statements.

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnin s Y r 3292 (in thousands)

Retained Earnings January 1 $ 278,814 $ 269,071 $ 235,107 Net Income ~96 8 ~4 ~4 ~57 53 Deductions:

Cash Dividends Declared:

Common Stock 117,464 131,260 112,508 Cumulative Preferred Stock:

4-1/8X Series 247 249 495 4.56X Series 67 88 273 4.12X Series 79 80 165 5.90X Series 985 985 2,360 6-1/4X Series 1,266 1,266 1,875 6.30X Series 834 834 2,205 6-7/8X Series 1,255 1,255 2,063 7.08X Series Total Cash Dividends Declared Capital Stock Expense Total Deductions 122,197

~8 136,017

~4122,475 Retained Earnings December 31 See /Yotes to Consolidated Financial Statements.

25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Regulation Organization As a subsidiary of AEP Co.,

Inc., the Company is subject to the Indiana Michigan Power Company regulation of the Securities and (the Company or I&M) is a wholly- Exchange Commission (SEC) under the owned subsidiary of American Electric Public Utility Holding Company Act of Power Company, Inc. (AEP Co., Inc.), 1935 (1935 Act). Retail rates are a public utility holding company. regulated by the Indiana Utility The Company is engaged in the Regulatory Commission (IURC) and the generation, purchase, sale, Michigan Public Service Commission transmission and distribution of (MPSC). The Federal Energy electric power to 554,000 retail Regulatory Commission (FERC) customers in its service territory in regulates wholesale rates.

northern and eastern Indiana and a portion of southwestern Michigan and Principles of Consolidation conducts business as American Electric Power (AEP). The Company The consolidated financial supplies electric power to the AEP statements include the revenues, System Power Pool (Power Pool) and expenses, cash flows, assets, shares the revenues and costs of liabilities and equity of I&M and its Power Pool'holesale sales to utility wholly-owned subsidiaries.

systems and power marketers. The Significant intercompany items are Company also sells wholesale power to eliminated in consolidation.

municipalities and electric cooperatives. As a member of the Basis of Accounting Power Pool and a signatory company to the AEP System Transmission As a cost-based rate-regulated Equalization Agreement, the Company's entity, I&M's financial statements gener ation and transmission reflect the actions of regulators facilities are operated in that result in the recognition of conjunction with the facilities of revenues and expenses in different certain other affiliated utilities as time periods than enterprises that an integrated utility system. are not rate regulated. In accordance with Statement of The Company has two wholly-owned Financial Accounting Standards (SFAS) subsidiaries, that were formerly 71, "Accounting for the Effects of engaged in coal-mining operations Certain Types of Regulation,"

which are consolidated in these regulatory assets (deferred expenses) financial statements, Blackhawk Coal and regulatory liabilities (deferred Company and Price River Coal Company. income) are recorded to reflect the Blackhawk Coal Company currently economic effects of regulation and to leases and subleases portions of its match expenses with regulated Utah coal rights, land and related revenues.

mining equipment to unaffiliated companies. Price River Coal Company, Use of Estimates which owns no land or mineral rights, is inactive. The Company's River The preparation of these Transportation Division provided financi al statements in conformi ty barging services to affiliated and with generally accepted accounting unaffiliated companies. principles requires in certain 26

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES instances the use of estimates. Amounts for the demolition and Actual results could differ from removal of non-nuclear plant are those e'stimates. charged to the accumulated provision for depreciation and recovered Vdi 1 i ty Plant through depreciation charges included in rates. The accounting and rate-Electric utility plant is stated making treatment afforded nuclear at ori ginal cost and is generally decommissioning costs and nuclear subject to first mortgage 1 iens. fuel disposal costs are discussed in Additions, major replacements and Note 3.

betterments are added to the plant

~

accounts. Retirements of plant are Cash and Cash Equivalents deducted from the electric utility plant in service account and are Cash and cash equivalents deducted from accumulated include temporary cash investments depreciation together with associated with original maturities of three lemoval costs, net of salvage. The months or less.

costs of labor, materials and overheads incurred to operate and Operating Revenues and Fuel Costs maintain utility plant are included in operating expenses. Revenues include the accrual of electricity consumed but unbilled at AllopIance for Funds Used During month-end as well as billed revenues.

Construction CAFVDC) Fuel costs are matched with revenues in accordance with rate commission AFUDC is a noncash nonoperating orders. Revenues are accrued related income item that is capitalized and to unrecovered fuel in both state recovered through depreciation over retail jurisdictions and for the service life of utility plant. replacement power costs in the It represents the estimated cost of Michigan jurisdiction until approved borrowed and equity funds used to for billing. If the Company's finance construction projects. The earnings exceed the allowed return in amounts of AFUDC for 1998, 1997 and the Indi ana jul i sdi cti on, the fuel 1996 were not significant. cl ause mechani sm provides for the refunding of the excess earnings to Depreciation and Amortization ratepayers. FERC wholesale jurisdictional fuel cost changes are Depreciation of electric utility expensed and billed as incurred.

plant is provided on a straight-line basis over the estimated useful lives Derivative Financial Instruments of utility plant and is calculated largely through the use of composite During 1998, the AEP Power Pool rates by functional class. The substantially increased the volume of annual composite depreciation rates its power marketing and trading for 1998, 1997 and 1996 are as transactions (trading activities) in follows: which the Company shares. Trading activities involve the sale of Functional Class

~rMrlUK3X Annual Composite electricity under physical forward 1222 12K contracts at fixed and variable Productionr Steam-Huclear 3.4% 3.4$ 3.4X prices and the trading of electricity Steam-Fossil-Fired 4.4$ 4.4X 4.4X contracts including exchange traded Hydroelectric-Conventional 3.4$

1.9X 3.2X 1.9X 3.2$

1.9$

futures and options and over-the-Transmission Distribution 4.2X 4.2X 4.2$ counter options and swaps. The General 3.8X 3.8X 3.8X majority of these transactions represent physical forward contracts 27

in the AEP System's traditional income. Certain prior year amounts marketing area and are typical ly have been reclassified to conform to settled by entering into offsetting current year presentation.'uch contracts. The net revenues from reclassifications had no impact on these transactions are included in previously reported net income.

operating revenues for ratemaking, accounting and financial 'nd Levelization of Nuclear Refueling regulatory reporting purposes. Outage Costs In addition the AEP Power Pool Incremental operation and enters into transactions for the maintenance costs associated with purchase and sale of electricity refueling outages at the Company's options, futures and swaps, and for Donald C. Cook Nuclear Plant (Cook the forward purchase and sale of Plant) are deferred commensurate electricity outside of the AEP Power with their rate-making treatment and Pool's traditional marketing area. amortized over the period beginning These non-regulated trading with the commencement of an outage activities are included in and ending with the beginning of the nonoperating income and accounted for next outage.

on a mark-to-market basis. The unrealized mark-to-market gains and Income Taxes losses from such non-regulated trading activity are reported as The Company follows the assets and liabilities, respectively. liability method of accounting for income taxes as prescribed by SFAS The Company enters into forward 109, "Accounting for Income Taxes."

contracts to manage the exposure to Under the liability method, deferred unfavorable changes in the cost of income taxes are provided for all debt to be issued. These temporary differences between the anticipatory debt instruments are book cost and tax basis of assets and entered into in order to manage the liabilities which will result in a change in interest rates between the future tax consequence. Where the time a debt offering is initiated and flow-through method of accounting for the issuance of the debt (usually a temporary differences is reflected period of 60 days). Any resultant in rates, deferred income taxes are gains or losses are deferred and provided with related regulatory amortized over the life of the debt assets and liabilities i n accordance issuance. There were no such forward with SFAS 71.

contracts outstanding at December 31, 1998 or 1997. Investment Tax Credits See Note 7 - Financial Investment tax credits have been Instruments, Credit and Risk accounted for under the flow-through Management for further discussion. method except where regulatory commissions have reflected investment Reel assi fica tion tax credits in the rate-making process on a deferral basis.

In the fourth quarter of 1998 Investment tax credits that have been the Company changed the presentation deferred are being amortized over the of its trading activities from a life of regulated plant investment.

gross basis (purchases and sales reported separately) to a net basis Oebt and Preferred Shock (purchases and sales are reported on a net basis as revenues). This Gains and losses from the reclassification had no impact on net reacquisition of debt are deferred as 28

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES regulatory assets and amortized over Other Property and Investments the remaining term of the reacquired debt i'n accordance with rate-making Other pr operty and investments treatment. If the debt is refinanced are stated at cost.

the reacquisition costs are deferred and amortized over the term of the Comprehensive Income replacement debt commensurate with their recovery in rates. There were no material differences between net income and Debt discount or premium and comprehensive income.

debt issuance expenses are deferred and amortized over the term of the related debt, with the amortization 2.

included in interest charges. ~PAN Redemption premiums paid to In accordance with SFAS 71 the reacquire preferred stock are consolidated financial statements included in paid-in capital and include regulatory assets (deferred amortized to retained earnings expenses) and regulatory liabilities commensurate with their recovery in (deferred income) recorded in rates. The excess of par value over accordance with regulatory actions in the cost of preferred stock order to match expenses and revenues reacquired is credited to paid-in from cost-based rates in the same capital and amortized to retained accounting period. Regulatory assets earnings. are expected to be recovered in future periods through the rate-Nuclear Decommissioning and Spent making process and regulatory Nuclear Fuel Oisposal Trust Funds liabilities are expected to reduce future cost recoveries. Among other Securities held in trust funds things, application of SFAS 71 for decommissioning nuclear requires that the Company's regulated facilities and for the disposal of rates be cost-based and recovery of spent nuclear fuel (SNF) are recorded regulatory assets must be probable.

at market value in accordance with Management has reviewed the evidence SFAS 115, "Accounting for Certain currently available and concluded Investments in Debt and Equity that the Company continues to meet Securities." Securities in the trust the requirements to apply SFAS 71.

funds have been classified as In the event a portion of the available-for-sale due to their long- Company's business no longer met term purpose. Due to the rate-making these requirements, that is, its process, adjustments for unrealized rates were no longer cost-based, gains and losses are not reported in regulatory assets and liabilities equity but result in adjustments to would have to be written off for that the liability account for the nuclear portion of the business and tangible decommissioning trust funds and to assets would have to be tested for regulatory assets or liabilities for possible impairment and if required the SNF disposal trust funds. an impairment loss recorded unless the net regulatory assets and impairment losses are recoverable as a stranded cost.

29

Recognized regulatory assets and 3.

liabilities are comprised of the following: Construction and Other Commitments m

122K 122Z (in thousands) Substantial construction Regulatory Assets: commitments have been made to support for Amounts Due From Customers Future Income Taxes $ 259,641 $ 277,966 the Company's utility operations Unrecovered Fuel and including the replacement of the Cook Purchased Pover Department of Energy 65.308 18,462 Plant Unit 1 steam generators. Such Decontamination and commitments do not include any Decoavnissioning Assessment Kuclear Refueling 38,898 42,648 expenditures for new generating Outage Cost Levelization 17,630 31,772 capacity. Construction program Unamortized Loss On expenditures for 1999-2001 are Reacquired Debt 16,434 17,210 estimated to be $ 366 million.

Other ~~4 Total Regulatory Asset ~4~4 ~4~4 Long-term fuel supply contracts Regulatory Liabilities: contain clauses that provide for Deferred Investment Tax Credits periodic price adjustments. The Other*

Total Regulatory Liabilities

~iE ~R

$ 129,779 $ 138,045 retail jurisdictions have fuel clause mechanisms that provide for recovery

~ Included in Deferred Credits on Consolidated Balance of changes in the cost of fuel with Sheets. the regulators'eview and approval.

The Rockport Plant consists of See Note 4 for changes in the fuel two 1,300 megawatt (mw) coal-fired clause mechanism in the Indiana units. I'M and AEP Generating jurisdiction proposed in a settlement Company (AEGCo), an affiliate, each agreement. The contracts are for own 50K of one unit (Rockport 1) and various terms, the longest of which each lease a 50X interest in the extends to 2014, and contain various other unit (Rockport 2) from clauses that would release the unaffiliated lessors under an Company from its obligation under operating lease. The gain on the certain force majeure conditions.

sale and leaseback of Rockport 2 was deferred and is being amortized, with The Company is committed under related taxes, over the initial lease unit power agreements to purchase all term which expires in 2022. of an affiliate's share, 50X of the 2,600 mw Rockport Plant capacity, At January 1, 1997 rate phase-in unless it is sold to other utilities.

plan deferrals existed for the The affiliate has a long-term unit Rockport Plant. Rate phase-in plans power agreement for the sale of 455 in the Company's Indiana and FERC mw to an unaffiliated utility.

jurisdictions provided for the Revenues received under this recover y and straight-1 ine agreement (which expires at the end amor tization of deferred Rockport of 1999) were $ 70 million in 1998.

Plant Unit 1 costs over ten years An agreement between the affiliate beginning in 1987. In 1997 the which owns Rockport Plant and another amortization and recovery of the affiliate provides for the sales of deferred Rockport Plant Unit 1 Phase- 390 mw of capacity to that affiliate in Plan costs were completed. During through 2004.

the recovery period net income was unaffected by the recovery of the The Company sells under contract phase-in deferrals. Amortization was up to 250 mw of its Rockport Plant

$ 11.9 million in 1997 and $ 15.6 capacity to an unaffiliated utility.

million in 1996. The contract expires in 2009.

30

I IANA MICHIGAIVPOWER COMPANY AND SUBSIDIARIES Nuclear Plant In January 1999 I&H announced that it will conduct additional

~ I&H owns and operates the two- engineering reviews at the Cook Plant unit 2, 110 mw Cook Plant under that will delay restart of the units.

licenses granted by the Nuclear Previously, the units were scheduled Regulatory Commission (NRC). The to return to service at the end of operation of a nuclear facility the first and second quarters of involves special risks, potential 1999. The decision to delay restart liabilities, and specific regulatory resulted from internal assessments and safety requirements. Should a that indicated a need to conduct nuclear incident occur at any nuclear expanded system readiness reviews. A power plant facility in the United new restart schedule will be States (US), the resultant liability developed based on the results of the could be substantial. By agreement expanded reviews and should be I&H is partially liable together with available in June 1999. When all other electric utility companies maintenance and other activities that own nuclear generating units for required for restart are complete, a nuclear power plant incident. In I&M will seek concurrence from the the event nuclear losses or NRC to return the Cook Plant to liabilities are underinsured or service. Until these additional exceed accumulated funds and recovery reviews are completed, management is in rates is not possible, results of unable to determine when the units operations, cash flows and financial will be returned to service. Unless condition would be negatively the costs of the extended outage and affected. 'estart efforts are recovered from customers, there would be a material Nuclear Plant'hutdown adverse effect on results of operations, cash flows and possibly I&M shut down both units of the financial condition.

Cook Plant in September 1997 due to questions, which arose during a NRC The costs incurred in 1997 and architect engineer design inspection, 1998 for restart of the Cook units regarding the operability of certain were $6 million and $ 78 million, safety systems. The NRC issued a respectively, and were recorded as Confirmatory Action Letter in operation and maintenance expense.

September 1997 requiring I&H to Reductions in other operation and address the issues identified in the maintenance expenses partially offset letter. I&H is working with the NRC these costs. Currently incremental to resolve the remaining open issue restart expenses are approximately in the letter. $ 12 million a month.

In April 1998 the NRC notified In July 1998 IEH received an I&H that it had convened a Restar t "adverse trend letter" from the NRC Panel for Cook Plant. A list of indicating that NRC senior managers required restart activities was determined that there had been a slow provided by the NRC in July 1998 and decline in performance at the Cook in October the NRC expanded the list. Plant during the 18 month period In order to identify and resolve the preceding the letter. The letter issues necessary to restart the Cook indicated that the NRC will closely units, I&M is and will be meeting monitor efforts to address issues at with the Panel on a regular basis, Cook Plant through additional until the units are returned to inspection activities. In October service.

31

1998 the NRC issued II%M a Notice of recovery of the replacement costs is Violation and proposed a $ 500,000 denied, future results of operations civil penalty for alleged violations and cash flows would be adversely at the Cook Plant discovered during affected by the writeoff of the five inspections conducted between regulatory asset.

August 1997 and April 1998. IICM paid the penalty. Nuclear Incident Liability The cost of electricity supplied Publ i c 1 i abi1 i ty i s 1 imi ted by to certain retail customers rose due law to $ 9 billion should an incident to the extended outage since higher occur at any licensed reactor in the cost coal-fired generation and coal US. Commercially available insurance based purchased power were provides $ 200 million of coverage.

substituted for low cost nuclear In the event of a nuclear incident at generation. IICM's Indiana and any nuclear plant in the US the Michigan retail jurisdictional fuel remainder of the liability would be cost recovery mechanisms permit the provided by a deferred premium recovery, subject to regulatory assessment of $ 88 million on each commission review and approval, of licensed reactor payable in annual changes in fuel costs including the installments of $ 10 million. As a fuel component of purchased power in result, IICM could be assessed $ 176 the Indiana jurisdiction and changes million per nuclear incident payable in replacement power in the Michigan in annual installments of $ 20 jurisdiction. The IURC approved, million. The number of incidents for subject to future reconciliation or which payments could be required is refund, agreements authorizing IICM, not limited.

during the billing months of July 1998 through March 1999, to include Nuclear insurance pools and in rates a fuel cost adjustment other insurance policies provide $ 3 factor less than that requested by billion of property damage, IICM. The agreements provide the decommissioning and decontamination parties to the proceedings with the coverage for Cook Plant. Additional opportunity to conduct discovery insurance provides coverage for extra regarding certain issues that were costs resulting from a prolonged raised in the proceedings, including accidental Cook Plant outage. Some the appropriateness of the recovery of the policies have deferred premium of replacement energy cost due to the provisions which could be triggered extended Cook Plant outage, in by losses in excess of the insurer's anticipation of resolving the issues resources. The losses could result in a future fuel cost adjustment from claims at the Cook Plant or proceeding. A regulatory asset in certain other unaffiliated nuclear the amount of $ 65 million of units. The Company could be assessed replacement energy costs has been up to $ 23.2 million annually under recorded at Oecember 31, 1998. See these policies.

Note 4 for discussion of proposed settlement agreement for the Indiana SNF Disposal jurisdiction.

Federal law provides for Hi stor i cal 1 y, the Company has government responsibility for been permitted to recover through the permanent SNF disposal and assesses fuel recovery mechanism the cost of nuclear plant owners fees for SNF replacement energy during outages. disposal. A fee of one mill per Management believes that it should be kilowatthour for fuel consumed after allowed to recover the deferred Cook April 6, 1983 is being collected from replacement energy costs; however, if customers and remitted to the US 32

IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES Treasury. Fees and related interest earnings increase the fund assets and of $ 190 million for fuel consumed the recorded liability and decrease pri or to April 7, 1983 have been the amount needed to be recovered r ecor ded as long-term debt. IKN has from ratepayer s. During 1998 the not paid the government the pre-April Company withdrew $ 3 million from the 1983 fees due to continued delays and trust funds and expects to withdraw uncertainties related to the federal $8 million in 1999 for disposal program. At December 31, decommissioning the original steam 1998, funds collected from customers generators removed from Unit 2. At towards payment of the pre-April 1983 December 31, 1998 and 1997, the fee and related earnings thereon Company has recognized a approximate the, liability. decommissioning liability of $ 446 million and $ 381 million, Oecommissioning and Los Level Paste respectively.

Accumulation Disposal Air guality Decommissioning costs are being accrued over the service life of the On September 24, 1998, the US Cook Plant. The licenses to operate Environmental Protection Agency the two nuclear units expire in 2014 (Federal EPA) finalized rules which and 2017. After expiration of the require reductions in nitrogen oxides licenses the plant is expected to be (NOx) emissions in 22 eastern states, decommissioned through dismantlement. including the states in which the The estimated cost of decommissioning generating plants of the Company and and low level radioactive waste its AEP Power Pool affiliates are accumulation disposal costs ranges located. The implementation of the from $ 700 million to $ 1,152 million final rules would be achieved thr ough in 1997 nondiscounted dollars. The the revision of state implementation wide range is caused by variables in plans (SIPs) by September 1999. SIPs assumptions including the estimated are a procedural method used by each length of time SNF may need to be state to comply with Federal EPA stored at the plant site subsequent rules. The final rules anticipate to ceasing operations. This, in the imposition of a NOx reduction on turn, depends on future developments utility sources of approximately 85K in the federal government's SNF below 1990 emission levels by the disposal program. Continued delays year 2003. On October 30, 1998, a in the federal fuel disposal program number of utilities, including the can result in increased decommission- Company and the other operating ing costs. The Company is recovering companies of the AEP System, filed estimated decommissioning costs in petitions in the US Court of Appeals its three rate-making jurisdictions for the District of Columbia Circuit based on at least the lower end of seeking a review of the final rules.

the range in the most recent decommissioning study at the time of Should the states fail to adopt the last rate proceeding. The the required revisions to their SIPs Company records decommissioning costs within one year of the date of the in other operation expense and final rules (September 24, 1999),

records a noncurr ent liability equal Federal EPA has proposed to implement to the decommissioning cost recovered a federal plan to accomplish the NOx in rates; such amount was $ 29 million reductions. Federal EPA also in 1998, $ 28 million in 1997 and $ 27 proposed the approval of portions of million in 1996. Decommissioning petitions filed by eight northeastern costs recovered from customers are states that would result in deposited in external trusts, which imposition of NOx emission reductions are described in Note 7. Trust fund on utility and industrial sources in 33

upwind midwestern states. These deductions for taxable years 1991-97 reductions are substantially the same to avoid the potential assessment by as those required by the final NOx the IRS of any additional above rules and could be adopted by Federal market rate interest on the contested EPA in the event the states fail to amount. The payments to the IRS are implement SIPs in accordance with the included on the balance sheet in final rules. other property and investments pending the resolution of this Prel iminary estimates indi cate matter. The Company will seek that compliance could result in refund, either administratively or required capital expenditures of through litigation, of all amounts approximately $ 169 million. paid plus interest. In order to Compliance costs cannot be estimated resolve this issue without further with certainty and the actual costs delay, on March 24, 1998, the Company incurred to comply could be filed suit against the US in the US significantly different from this District Court for the Southern preliminary estimate depending upon District of Ohio. Management the compliance alternatives selected believes that it has a meritorious to achieve reductions in NOx position and will vigorously pursue emissions. Unless such costs are this lawsuit. In the event the recovered from customers, they would resolution of this matter is have a material adverse effect on unfavorable, it will have a material results of operations, cash flows and adverse impact on results of possibly financial condition. operations and cash flows.

Litigation The Company is involved in a number of other legal proceedings and The Inter nal Revenue Servi ce claims. While management is unable

( I RS) agents auditing the AEP to predict the ultimate outcome of System's consolidated federal income litigation, it is not expected that tax returns for the years 1991 to the resolution of these matters will 1993 requested a ruling from their have a material adverse effect on the National Office that certain interest results of operations, cash flows and deductions claimed by the Company financial condition.

relating to a corporate owned life insurance (COLI) program should not be allowed. As a result of a suit 4. NT V NT M NT filed by the Company in US District Court (discussed below) the request for ruling was withdrawn by the IRS On March 16, 1999 a settlement agents. Adjustments have been or agreement was filed with the IURC will be proposed by the IRS resolving all matters related to the disallowing COLI interest deductions reasonableness of fuel costs and all for taxable years 1991-96. A outage issues during an extended disallowance of the COLI interest outage of the Cook Plant. The deductions through December 31, 1998 settlement agreement, which is would reduce earnings by subject to IURC approval, provides approximately $ 66 million (including for, among other things, a credit of interest). The Company has made no $ 55 million to Indiana retail provision for any possible adverse customers; authorization to defer any earnings impact from this matter. unrecovered fuel revenues accrued between September 9, 1997 and In 1998 the Company made December 31, 1999 including the $ 55 payments of taxes and interest million; authorization to defer up to attributable to COLI interest $ 150 million of incremental operation

I ANA MICHIGANPOWER COMPANY AND SUBSIDIARIES and maintenance restart costs for the supplied to the AEP Power Pool as Cook Plant above the base rate level follows:

incurred during 1999; amortization of 1222 1222 12K the fuel recoveries and restart cost ((n thousands) deferrals over a five-year period Capac(ty Revenues 33,011 53.282 57.594 ending December 31, 2003; a freeze in $ $ $

Energy Revenues ~4 5 ~4 il MEGAL base rates though December 31, 2003; and a cap on fuel recovery charges Total ~37 56 QQ~4 ~5~756 through March 1, 2004. The $ 55 Purchased power expense includes million credit will be refunded charges of $ 125.2 million in 1998, through customer's bills during the $ 51 million in 1997 and $ 34.5 million months of July, August and September in 1996 for energy received from the 1999. If the IURC does not approve AEP Power Pool.

the settlement, the issue of recovery of replacement energy costs would be Power marketing and trading resolved through regulatory operations, which are described in hearings. Unless the costs of the Note 1, are conducted by the AEP extended outage and restart efforts Power Pool and shared with the are recovered from customers, there Company. The Company's operating would be a material adverse effect on revenues, purchased power expense and results of operations, cash flows, nonoperating income include amounts and possibly financial condition. for power marketing and trading allocated by the AEP Power Pool as follows:

5. Ih 1222 122l 1299.

costs of the AEP ((n thousands)

Benefits and Operat(ng Revenues $ 124,973 $ 74,895 $ 73,424 System's generating plants are shared Purchased Power Expense 71,588 15,415 8,098 by members of the AEP Power Pool of Honoperat(ng Loss (7,122) (61) which the Company is a member. Under The cost of Rockport Plant power the terms of the AEP System purchased from AEGCo, an affiliated Interconnection Agreement, capacity company that is not a member of the charges and credits are designed to Power Pool, was included in AEP allocate the cost of the AEP System's purchased power expense in the capacity among the AEP Power Pool amounts of $ 86.2 million, $ 87.5 members based on their relative peak demands and generating reserves. AEP million and $ 85.4 million in 1998, 1997 and 1996, respectively.

Power Pool .members are also compensated for the out-of-pocket The cost of power purchased from costs of energy delivered to the AEP Ohio Valley Electric Corporation, an Power Pool and charged for energy affiliated company that is not a received from the AEP Power Pool. member of the AEP Power Pool, was The Company is a net supplier to the included in purchased power expense AEP Power Pool and, therefore, in the amounts of $ 14.3 million, $ 11 receives capacity credits from the million and $ 10.7 million in 1998, AEP Power Pool. 1997 and 1996, respectively.

Operating revenues include The Company operates the revenues for capacity and energy Rockport Plant and bills AEGCo for its share of operating costs.

35

AEP System companies participate 6.

in the AEP System Transmi ssi on Equalization Agreement. This Effective December 31, 1998 the agreement combines certain AEP System Company adopted SFAS 131, companies'nvestments in "Disclosures about Segments of an transmission facilities and shares Enterprise and Related Information".

the costs of ownership in proportion The Company has one reportable to the AEP System segment, a regulated vertically peak demands. Pursuant to integrated electricity generation and companies'espective the terms of the agreement, since the energy delivery business. All other Company's relative investment in activities are insignificant. The transmission facilities is greater Company's operations are managed on than its relative peak demand, other an integrated basis because of the operation expense includes substantial impact of bundled cost-equalization credits of $ 44. 1 based rates and regulatory oversight million, $ 46.1 million and $ 46.3 on business processes, cost million in 1998, 1997 and 1996, structures and operating results.

respectively. Aggregated in the regulated electric utility segment is the power Revenues from providing barging marketing and trading activiti es that services were recorded in are discussed in Note 1 and the nonoperating income as follows: Company's barging activities. For the years ended December 31, 1998, 122k 122Z 12K 1997 and 1996, all revenues are (5n thousands) derived in the US.

Affflfated Coepanfes 523,494 524,427 522,740 Unaffflfated Total CNapan5es ~4 ~56 7.. NT T AN

~35 984 gg 810 N M R American Electric Power Service Corporation (AEPSC) provides certain The Company is subject to market managerial and professional services risk as a result of changes in to AEP System companies including the electricity commodity prices and Company. The costs of the services interest rates. The Company are billed by AEPSC to its affiliated participates in the AEP Power Pool's clients on a direct-charge basis power marketing and trading operation whenever possible and on reasonable that manages the exposure to bases of proration for shared electricity commodity price movements services. The billing for services using physical forward purchase and are made at cost and include no sale contracts at fixed and variable compensation for the use of equity prices, and financial derivative capital, which is furnished to AEPSC instruments including exchange traded by AEP Co., Inc. Billings from AEPSC futures and options, over-the-counter are capitalized or expensed depending options, swaps and other financial on the nature of the services derivative contracts at both fixed rendered. AEPSC and its billings are and variable prices. Physical subject to the regulation of the SEC forward electricity contracts within under the 1935 Act. the AEP Power Pool's traditional marketing area are recorded on a net basis as operating revenues in the month when the physical contract settles. The Company's share of the net gains from these regulated transactions for the year ended December 31, 1998 was $ 21 million.

36

IANA MICHIGANPOWER COMPANy'ND SUBSIDIARIES Physical forward electricity December 31, 1998 and 1997 are contracts outside the AEP Power summa ri zed in the fol 1 owing tabl e.

Pool's traditional marketing area and The fair values of long-term debt and all financial electricity trading preferred stock are based on quoted transactions including exchange market prices for the same or similar traded contracts that are marked to issues and the current dividend or market and recorded in nonoperating interests rates offered for income. The Company's share of the instruments of the same remaining net losses from these non-regulated maturities. The fail value of those tl'ading transactions for the year financial instruments that are ended December 31, 1998 was $ 7 marked-to-market are based on million. The unrealized mark-to- management's best estimates using mar ket gains and losses from such over-the-counter quotations, exchange trading of financial instruments are plices, volatility factors and reported as assets and liabilities, valuation methodology. The estimates respectively. These activities were presented her ein are not necessarily not material in prior periods. indicative of the amounts that the Company could realize in a current The Company is exposed to risk market exchange. At December 31, from changes in interest rates 1997 the notional amounts and fair primarily due to short-term and long- values of derivatives were not term borrowings used to fund its material.

business operations. The debt portfolio has both fixed and variable ~ova1ue ~F1r u ue (in thousands) interest rates with terms from one Non-Derivatives day to forty years and an average 1998 duration of six years at December 31, 1998. A near term change in interest Long-term Debt $ 1,175,800 $ 1,235,200 rates should not materially affect Preferred Stock 68,400 72,600 results of operations or financial position since the Company would not 1997 expect to liquidate its entire debt Long-ters Debt 1.049,200 1,094 '00 portfolio in a one year holding period. Also since the,Company's Preferred Stock 68,400 73,300 rates are cost-based regulated, the Derivatives risk of interest rate changes on debt used to finance regulated operations 1998 is mitigated.

( 1n thousands)

Market Va7(Iat ion Q~fn

~~ri Physical s 8,700 7,700 The book value of cash and cash Options 6 '00 15,300 equivalents, accounts receivable, Swaps 600 200 short-term debt and accounts payable approximate fair value because of the short-term maturity of these fllect t, instruments. The book value of the Futures (1,300)

(9,400)

(300)

(8,800)

Physicals pre-April 1983 spent nuclear fuel Options (5,700) (15,200) disposal liability approximates the Swaps (1,400) (400)

Company's best estimate of its fair the value. At December 31, 1998 notional amounts of the Company's The book value amounts and fair nonregulated electric trading values of the Company's share of- physical forward contract purchases significant financial instruments at and sales are 1,912 Gigawatt hours 37

(Gwh) and 2,044 Gwh, respectively; to negatively affect a counter the notional amounts for fixed priced party's credit position, the AEP swaps purchases and sales are 70 Gwh Power Pool requires further credit and 75 Gwh, respectively; and the enhancements to mitigate lisk. Since notional amounts for options to the formation of the power marketing purchase and to sell are 1,381 Gwh and trading business in July of 1997, and 992 Gwh, respectively. The the Company has experienced no Company has a net long position of 74 significant losses due to the credit Gwh for electric future contracts. risk associated with risk management activities; furthermore, the Company At December 31, 1998 the fair does not anticipate any future value of the assets and liabilities material effect on its results of related to the wholesale electric operations, cash flow or financial forward contracts was $ 69 million and condition as a result of counter

$ 67 million, respectively. The party nonperformance.

related notional amounts were 9,094 Gwh for purchases and 9,280 Gwh for Nuc1 ear Trust Funds Recorded a t sales. The average fair value Pfarket Value amounts outstanding duling the period were $ 175 million of assets and $ 167 The Nuclear Decommissioning and million of liabilities. Spent Nuclear fuel Disposal Trust Fund investments are recorded at Credit and Risk management market value in accordance with SFAS 115 and consist of tax-exempt In addition to market risk municipal bonds and other securities.

associated with price movements, the Company through the AEP Power Pool is At December 31, 1998 and 1997 also subject to the credit risk the fair values of trust fund inherent in its risk management investments were $ 648 million and activities. Credit risk refers to $ 566 million, respectively.

the financial risk arising from Accumulated gross unrealized holding commercial transactions and/or the gains were $ 65 million and $ 41 intrinsic financial value of million and accumulated gross contractual agreements with trading unrealized holding losses were $ 1. 1 counter parties, by which there million and $ 1 ' million at December exists a potential risk of 31, 1998 and 1997, respectively. The nonperformance. The AEP Power Pool change in market value in 1998, 1997 has established and enforced credit and 1996 was a net unrealized holding policies that minimize this risk. gain of $ 24 million, $ 19. 1 million The AEP Power Pool accepts as counter and $ 2.6 million, I'espectively.

parties to forwards, futures, and other derivative contracts primarily The trust fund investments'ost those entities that are classified as basis by security type were:

Investment Grade, or those that can be considered as such due to the 122K 122Z effective placement of credit (in thousands) enhancements and/or collateral Tax-Exempt Bonds Equity Securities S326,239 95 '54

$ 335,350 74,398 agreements. Investment grade is the Treasury Bonds 71,194 44 '00 designation given to the foul highest Corporate Bonds Cash, Cash Equivalents 10,661 9,167 debt rating categories (ice., AAA, and Interest Accrued ~49K AA, A, BBB) of the major rating Total DR4~0 services, e.g., ratings BBB- and Proceeds from sales and above at Standard & Poor's and Baa3 and above at Hoody's. Mhen adverse maturities of securities of $ 225 market conditions have the potential million during 1998 resulted in $ 8.2 38

I IANA MICHIGANPOWER COMPANY AND SUBSIDIARIES million of realized gains and $ 2.8 Severance accruals totaling $ 3.7 million of realized losses. Proceeds million were recorded in December from sales and maturities of 1998 for reductions in power securities of $ 147.3 million during generation and energy delivery staffs 1997 resulted in $ 3 ' million of and were charged to other operation realized gains and $ 1.4 million of expense in the Consolidated realized losses. Proceeds from sales Statements of Income. In the first and maturities of securities of quarter of 1999 the power generation

$ 115.3 million during 1996 resulted and energy delivery staff reductions in $ 2.6 million of realized gains and were made.

$ 2. 1 million of realized losses. The cost of securities for determining realized gains and losses is original 9. NF P N acquisition cost including amortized premiums and discounts. The Company and its subsidiaries participate in the AEP System At December 31, 1998, the year qualified pension plan, a defined of maturity of trust fund benefit plan which covers all investments, other than equity employees. Net pension costs for the securities, was: years ended December 31, 1998, 1997 (fn thousands) and 1996 were $ 2. 1 million, $ 2. 1 million and $ 4. 1 million, 1999 4106,316 respectively.

2000-2003 157,224 2004-2008 175,751 After 2000 KR Postretirement benefits other Total 144!@F2 than pensions ar e provided for retired employees for medical and

8. death benefits under an AEP System plan. The Company's annual accrued During 1998 an internal costs for 1998, 1997 and 1996 were evaluation of the power generation $ 12 million, $ 11.5 million and $ 12.8, organization was conducted with a million, respectively.

goal of developing a better organizational structure for a A defined contribution employee competitive generation market. The savings plan required that the study was completed in October 1998. Company make contributions to the In addition, a review of energy plan totaling $ 4 million in 1998 and delivery staffing levels was 1997 and $ 3.7 million in 1996.

conducted in 1998. As a result approximately 80 power generation and energy delivery positions were identified for elimination.

39

10.

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

n III I'22Z (in thousands)

Charged (Credited) to Operating Expenses (net):

Current $ 38.165 $ 75,442 $ 110,133 Deferred Deferred Investment Tax Credits Total

~le)

~~4 21,073

~~44 3,088 (24,730)

~24)

~i22 Charged (Credited) to Nonoperating Income (net):

Current (594) 3,287 182 Deferred Deferred Investment Tax Credits Total (3,168)

~>ZX)

~4~4)

~4)

~4) 834

~!K)

~0) 43 Total Federal Income Taxes as Reported ~4~ ~74 ~~8<>

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.

Y r nd III I'22Z (in thousands)

Net Income $ 96,628 $ 146,740 $ 157,153 Federal Income Taxes ~252 Pre-tax Book Income &446K &4M'VJL2H

~4 Federal Income Tax on pre-tax Book Income at Statutory Rate (355) $ 50 '43 $ 77,337 $ 81,918 Increase (Decrease) in Federal Income Tax Resulting From the Following Items:

Depreciation 17,257 14,082 13 F 880 Corporate Owned Life Insurance (3,263) (3>348) (2,178)

Nuclear Fuel Disposal Costs (3,397) (3 '86) (3,096)

Investment Tax Credits (net) '28)

Other Total Federal Income Taxes as Reported

~4

~4 (8,266)

4) ~4)

~74 (8

~4)

~7 (8,729)

Effective Federal Income Tax Rate The following tables show the elements of the net deferred tax liability and the significant temporary differences giving rise to such deferrals:

~8 ~7 (in thousands)

Deferred Tax Assets 226,118 Deferred Tax Liabilities Net Deferred Tax Liabilities

~~4)

~7~4) 223,772 Property Rel a ted Tempo ra ry Di erences ff $ (460,077) $ (471,898)

Amounts Due From Customers For Future Federal Income Taxes (69,102) (74,282)

Deferred State Income Taxes (62,302) (65,679)

Deferred Gain on Sale and Leaseback of Rockport Plant Unit 2 31,049 32,347 Accrued Nuclear Decommissioning Expense All Other (net)

Net Deferred Tax Liabilities 29,930 am~88)

) ~7~)

kab5'> 77.8) 26,991 40

IAIVAMICHIGANPOWER COMPANY AND SUBSIDIARIES The Company and its subsidiaries earnings, for the payment of cash join in the filing of a consolidated dividends on common stock. At federal income tax return with their December 31, 1998, $ 5.9 million of affiliates in the AEP System. The retained earnings were restricted.

allocation of the AEP System's Regulatory approval is required to curl ent consolidated federal income pay dividends out of paid-in capital.

tax to the AEP System companies is in accordance with SEC rules under the In 1998, 1997 and 1996 net 1935 Act. These rules permit the changes to paid-in capital of allocation of the benefit of current $ 133,000, $ 1,200,000 and $ 170,000 tax losses to the System companies respectively, represented gains and giving rise to them in determining expenses associated with cumulative their current tax expense. The tax preferred stock transactions.

loss of the parent company, AEP Co.,

Inc., is allocated to its subsidiaries with taxable income. 12. P H Y NF MATI N:

With the exception of the loss of the parent company, the method allocation approximates a separate of 12'22 Y nd (fn thousands) mb 12K return result for each company in the consolidated group. Cash was pa(d for:

Interest (net of capital(zed The AEP System has settled with amounts)

Income Taxes 566,313 36,413 S 62,274 120,212 S 64,117 125,707 the IRS all issues from the audits of the consolidated federal income tax Honcash Acquf s(t(ons returns for the years prior to 1991. Under Capftal Leases 9,658 111,395 48,305 Returns for the years 1991 through In connection with the 1996 1996 are presently being audited by early termination of a western coal the IRS. With the exception of land sublease the Company will interest deductions related to COLI, receive cash payments from the lessee which are discussed under the of $ 30.8 million over a ten-year heading, Litigation, in Note 3, period which was recorded at a net management is not aware of any issues present value of $ 22.8 million. The for open tax years that upon final long-term portion of this receivable resolution are expected to have a is recorded as other property and material adverse effect on results of investments and the culrent portion operations. is recorded as miscellaneous accounts receivable.

~

Y Hortgage indentures, charter provisions and orders of regulatory author ities place various restrictions on the use of retained 41

13.

At December 31, 1998, authorized shares of cumulative preferred stock were as follows:

2)~~l har th ri d

$ 100 2,250,000 25 11,200,000 The cumulative preferred stock is callable at the price indicated below 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. During 1996 the Company redeemed and canceled 300,000 shares of the 7.08K series not subject to mandatory redemption.

~~r 4-1/8X 4.56%

4.12K

~

A. Cumulative Preferred Call Price December 31,

$ 106.125 102 102.728 Par Giga

$ 100 100 100 Stock Not Subject to Mandatory Redemption:

Number 771 650 200 of Shares 59,760 44,788 20,869 m

Redeemed 233 Shares Outstanding 59,236 14,562 18,931 1229 5,924 1,456 m

3 129Z (in thousands) 6,001 1,521 XK222 B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Shares Amoun Par Number of Shares Redeemed

~a r 0 mbr3 cemb r 3 8 (in thousands) 5.90$ (b) $ 100 233,000 167.000 $ 16,700 $ 16,700 6-1/4X(b) 100 97,500 202,500 20,250 20,250 6.30K (b) 100 217,550 132,450 13,245 13,245 6-7/8%(c) 100 117,500 182,500

~68 445 ~68 445 (a) Not callable until after 2002. There are no aggregate sinking fund provisions through 2002.

A sinking fund provision requires the redemption of 15,000 shares in 2003.

(b) Commencing in 2004 and continuing through 2008 the Company may redeem, at $ 100 per share, 20,000 shares of the 5.90K series, 15,000 shares of the 6-1/4X series and 17,500 shares of the 6.30K series outstanding under sinking fund provisions at its option and all remaining outstanding shares must be redeemed not later than 2009. Shares redeemed in 1997 may be applied to meet the sinking fund requirement.

(c) Commencing in 2003 and continuing through the year 2007, a sinking fund will require the redemption of 15,000 shares each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at $ 100 per share. Shares redeemed in 1997 may be applied to meet the sinking fund requirement.

42

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES

14. control revenue bonds 'by governmental authorities as follows:

Long-term debt by major 1222 1227 category was outstanding as follows: (1n thousands)

~%Ra Du cembe 3 City of Lawrenceburg, Ind1ana:

1222 122l 7.00 2015 - Apr11 1 $ 25,000 $ 25,000 (in thousands) 5.90 2019 - Hovember 1 52,000 52,000 City of Rockport, Indiana:

First Hortgage Bonds 1 466,330 $ 520,317 (a) 2014 - August 1 50,000 50 000 F

Installment Purchase 7.60 2016 - Harch 1 40.000 40,000 Contracts 309,418 309,269 6.55 2025 - June 1 50,000 50,000 Senior Unsecured Hotes 48,559 (b) 2025 - June 1 50,000 50,000 Other Long-term Debt (a) 190,192 180,837 City of Sullivan, Indiana:

Junior Debentures ~6LZl (I ~KJD4 Less Portion Oue Hithin 1,175,789 1,049,237 5.95 2009 - Hay 1 Unamortized D1scount ~E) 45,000 45,000 One Year Total L3304 8 Total HJ4RZ62 F44'R (a) A variable,interest rate 1s determined weekly. The average weighted interest rate (a) Represents a SHF disposal liability including was 4.1X for 1998 and 4.3% for 1997.

1nterest accrued payable to the Department of Energy. (b) An adjustable interest rate can be a daily, See Hote 3. weekly, cosgaercial paper or term rate as designated by the Company. A weekly rate was First mortgage bonds out- selected which ranged from 2.75 to 4.3% in 1998 and from 3.05 to 4.6% in 1997 and standing were as follows: averaged 3.6X and 3.8X during 1998 and 1997

'espectively.

1222 1227 (in thousands) Under the terms of certain

~Ra u

- Hay 1 installment purchase contracts, the 7.00 35,000 1998 Company is required to pay amounts 7.30 1999 - December 15 35,000 35,000 6.40 2000 - Harch 1 48,000 48,000 sufficient to enable the cities to 7.63 7.60 2001 2002

- June 1

- Hovember 1 40,000 50 000 40,000 50,000 pay interest on and the principal (at 7.70 2002 - December 15 F

40,000 40,000 stated maturities and upon mandatory 6.80 2003 - July 1 20,000 20,000 redemption) of related pollution 6.55 6.10 2003 2003 October Hovember 1

1 20,000 30 000 20,000 30,000 control revenue bonds issued to finance the construction of pollution F

6.55 2004 - Harch 1 25,000 25,000 8.50 7.80 2022 2023 December 15 July 75,000 75,000 20,000 control facilities at certain 7.35 2023 - October 1

1 20,000 20,000 generating plants. On the two 7.20 2024 - February 1 40,000 40,000 variable rate seiies the principal is 7.50 2024 - March Unamortized Discount (net) 1 25,000

~~D25,000 payable at the stated maturities or 466,330 520,317 on the demand of the bondholders at Less Portion Due llithin One Year ~KJHHI 14'%2K

~AULD

~4'~7 periodic interest adjustment dates Total The variable which occur weekly.

Certain indentures relating to rate bonds due in 2014 are supported the fiist mortgage bonds contain by a bank letter of credit which improvement, maintenance and expires in 2002. I&M has agreements replacement provisions requiring the that, provide for brokers to remarket deposit of cash or bonds with the the adjustable rate bonds due in 2025 trustee, or in lieu thereof, tendered at interest adjustment certification of unfunded property dates. In the event certain bonds additions. cannot be remarketed, I&M has a standby bond purchase agreement Installment purchase contiacts with a bank that provides for the have been entered into in connection bank to purchase any bonds not with the issuance of pollution remarketed. The purchase agreement 43

expires in 2000. Accordingly, the Outstanding short-term debt consisted variable and adjustable rate of:

installment purchase contracts have been classified for repayment Outstanding Year-en'alance

'Neighted Average purposes based on the expiration ~in Lhh)~n dates of the standby purchase December 31, 1998:

agreement and the letter of credit. Commercial Paper 6.2%

December 31, 1997:

In November 1998 the Company Notes Payable $ 56,410 6.3X Commercial Paper 6.8 issued $ 50,000,000 of 6.45X senior Total H1KHQ 6.6 unsecui'ed notes due November 10, The unamortized discount at 2008.

December 31, 1998 was $ 1,441,000. 15. ~Q:

Junior debentures are composed Leases of property, plant and of the following: equipment are for periods of up to 35 m years and require payments of related UZR (in thousands) l222 property taxes, maintenance and operating costs. The Company is 8.00 2026 - Harch 31 $ 40,000 $ 40,000 leasing 50K of the 1,300 mw Rockport 2038 - June 30 7.60 125.000 2 generating unit under an operating Unamortized Discount Total DH~ lease. The lease has 24 years remaining and total minimum lease Inter est may be defer red and payments of $ 1.8 billion. The payment of principal and interest on majority of the leases have purchase the junior debentures is subordinated or renewal options and will be and subject in right to the prior renewed or replaced by other leases.

payment in full of all senior indebtedness of the Company. Lease rentals for both operating and capital leases are At December 31, 1998, future generally charged to operating follows'mn annual long-term debt payments are as (in thousands) expenses in accordance with rate-making treatment.

rental costs are as follows:

The components of 1999 $ 35,000 Yar n 2000 98,000 1998 1297 2001 40,000 (in thousands) 2002 140,000 2003 70,000 Lease Payments on Later Years Operating Leases $ 88,297 $ 92,067 $ 96,096 Total Principal Amount 1,185.192 Amortization of Unamortized Discount 1~41) Capital Leases 10,717 42,882 55 '89 Total Interest on Capital I Leases MVZZ MVL4 II Total Lease Short-term debt borrowings are Rental Costs Q44~i limited by provisions of the 1935 Act to $ 300 million. Lines of credit are shared with AEP System companies and at December 31, 1998 and 1997 were available in the amounts of $ 763 million and $ 442 million, respectively. Facility fees of approximately 1/10 of 1X of the short-term lines of credit are required by the banks to maintain the lines of credit.

44

I NA MICHIGANPOWER COMPANY'ND SUBSIDIARIES Properties under capital leases Future minimum lease payments and related obligations recorded on consisted of the following at the Con'solidated Balance Sheets are December 31, 1998:

Hon-as follows: Cancelable Capital Operating emb

~a ~ea 12K 1222 (in thousands)

(in thousands)

Electric Utility Plant Under 1999 5 15,807 $ 98,992 Capital Leases: 2000 14,371 98,729 Production Plant 5 8,850 5 9,218 2001 12,524 97,494 Distribution Plant 14,645 14,660 2002 18,521 95,778 General Plant: 9,141 95,685 2003 Huclear Fuel (net of amort1zat1on) 103,939 103,939 Later Years ~L2K Other Plant Total Future Minimum Total Electric Utility Plant Lease Payments 108,869(a) ~~4 5 Under Capital Leases Accumulated Amortizat1on Het Electric Utility Plant 187,436

~31 4 ~i(I 189,085 Less Estimated Interest Element Under Capital Leases ~5:~4%

Estimated Present Other Property Under Value of Future Capital Leases 376672 40,746 Accumulated Amortization ~~4 M1nimum Lease Payments 82,488 Het Other Property Under Unamortized Huclear Capital Leases Het Properties Under Fuel Mh232 Total ~366 4 1 Capital Leases 119~4 51K~

Capital Lease Obligations*: (a) Excludes nuclear fuel rentals Honcurrent Liability $ 176,760 5161,194 which are paid in proportion to heat Liability Due Uithin produced and carrying charges on One Year Total Capital Lease the unamortized nuclear fuel Obligations 03~4 DR~) balance. There are no minimum

• Represents the present value of future minimum lease lease payment requirements for leased payments. nuclear fuel.

The noncurrent portion of capital lease obligations is included 16. T ART N A in other noncurrent liabilities in D Y I NF RUAT I N:

the Consolidated Balance Sheets.

Properties under operating leases and Het Quarterly Periods Operating Operating Income related obligations are not included ~hC 4 in the Consolidated Balance Sheets. (in thousands) 1998 March 31 5328,468 551.368 533,744 June 30 348,271 42,194 2'36 September 30 412,908 58,639 38,691 December 31 316,147 13,806 (4 '43) 1997 March 31 341,313 59,894 44,259 June 30 320,508 50,140 33,908 September 30 347,668 60,449 45,091 December 31 329,743 37,305 23,482 Fourth quarter 1998 operating income and net income declined primarily as a result of expenditures to prepare the nuclear units for restart.

See "Reclassification" in Note 1 regarding reclassification of prior period amounts.

45

OPERATING STATISTICS

~

~4 OPERATING REVENUES (in thousands):

Retail:

Residential:

Without Electric Heating $ 265,442 $ 237,475 $ 232,212 $ 239,266 $ 227,358 With Electric Heating Total Residential

~UL2K 374,392

~~HZ348,022 343,768

~(LLEW 348,770 334,881 Commercial 290,149 264,031 253,750 256,319 247,938 Industrial 370,329 332,218 312,777 298,256 291,527 Hiscellaneous R Total. Retail

~L22l ~6~**

1,041,719 Wholesale (sales for resale)

Total Revenues from 950,736 916,740 899348 ~~4 909,827 880,662

~5889 Energy Sales 1,363,490 1,313,128** 1,308,218 1,267,268 1,233,551

~L2K

~~ ~~

Other Total Operating Revenues J1 339 ~** ~32~4 Mal.292 SOURCES AND USES OF ENERGY (in millions of kilowatthours):

Sources:

Net Generated:

Fossil Fuel 13,432 14,193 13,304 12,850 13,022 Nuclear Fuel

• 10,421 16,396 13,999 9,291 Hydroelectric U2 Total Net Generated 13,548 24,747 29,799 26,935 22,408 Purchased and AEP Power Pool 12 Kl ~~+* ~5/Q ~QH 5 757 Total Sources 27,169 34,304** 37,380 32,806 28,165 Less: Losses, Company Use, Etc. ~rK Net Sources 2f7~

UK

~~44** ~5 ~ZQQ K

Uses; Retail Sales:

Residential:

Without Electric Heating 3,518 3,307 3,329 3,390 3,210 With Electric Heating Total Residential

~Sly 5,134

~ZH 5,075

~911 5, 140

~lH 5,158

~ZZZ 4,937 Commercial 4,540 4,349 4,328 4,300 4,148 Industrial 7,755 7,541 7,295 6,582 6,453 Miscellaneous Total Retail 17,515 17,047 16,845 16,122

~8 15,620 Wholesale Sales (sales for resale) g5~** ZLZZ 11 HZ Total Uses ZRZ5 ~45+** ~5M5 31 1K 26~6

• During 1998 the Company's nuclear plant was shutdown for an extended outage which began in September 1997 to address certain safety concerns. See Note 3.

• • Reclassified

I NA MICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS (Concluded)

AVERAGE COST OF FUEL CONSUMED (in cents):

Per Million Btu: 130 89 74 78 85 Per Kilowatthour Generated: 1.21 .93 .80 .83 .90 RESIDENTIAL SERVICE - AVERAGES:

Annual Kwh Use per Customer:

With Electric Heating 15,922 17,583 18,206 18,044 17,907 Total 10,566 10,560 10,791 10,943 10,572 Annual Electric Bill:

With Electric Heating $ 1,073.77 $ 1,099.34 $ 1,121.41 $ 1,117.55 $ 1,115.19 Total $ 770 '0 $ 724.16 $ 721.76 $ 739 '9 $ 717.17 Price per Kwh (in cents):

With Electric Heating 6.74 6.25 6.16 6.19 6.23 Total 7.29 6.86 6.69 6.76 6.78 NUMBER OF CUSTOMERS:

Year -End:

Retail:

Residential:

Without Electric Heating 386,253 383,314 378,757 375,929 372,473 With Electric Heating 1KJ29 ~49+ 1EL2l? ~325. <)~4 Total Residential 488,331 484,806 479,129 475,034 469,875 Commercial 58,720 57,311 55,869 55,077 53,927 Industrial 5,437 5,484 5,345 5,316 5,213 Miscellaneous ~%6 ~55. ~JQ9 ~22Z Total Retail Wholesale (sales for resale)

Total Electric Customers 554,444 md '56 549,456 244.~

~5 542,163 k4?-~4 537,224 53LZJK

~4 530,821 47

DIVIDENDS AND PRICE RANGES OF CUMULATIVE PREFERRED STOCK B Quarters (1998 and 1997)

($ 100 Par Value) 4-1/BX 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 (CSE) - 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 Harket Price - $ Per Share (OTC)

Ask - High

- Low Bfd High 58-1/2 66 67-5/8 68 52 52 57-5/8 58-1/4

- Low 58-1/4 58-1/2 66 64 52 52 52 57-5/8 4.12% Series Dividends Pafd Per Share $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 Harket Price - $ Per Share (OTC)

Ask - High

- Low Bfd - High 59 3/8 63-7/8 64-5/8 67-3/8 63-1/8 58 58-1/4 58-1/4

- Low 58-1/4 59-3/8 63-7/8 64-5/8 50 58 58 58-1/4 5.90K Series Dividends Paid Per Share $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 1.475 Market Price - $ Per Share (OTC)

Ask (high/low)

Bfd (high/low) 6-1/4X Series Dividends Paid Per Share $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6.30K Series Dividends Paid Per Share $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 $ 1.575 Market Price - $ Per Share (OTC)

Ask (high/low)

Bfd (high/low) 6-7/BX Series Dividends Paid Per Share $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 Harket Price - $ Per Share (OTC)

Ask (high/low)

Bfd (high/low)

CSE - Chicago Stock Exchange OTC - Over-the-Counter Kote - The above bfd and asked quotatfons represent prices between dealers and do not represent actual transactions.

Market quotations provided by Hatfonal Quotation Bureau, Inc.

Dash indicated quotation not available.

48

NDIANA AIICHIGANPOWER COAIPANY INVESTOR INQUIRIES Investors should direct inquiries to Investor Services using the toll free number, 1-800-AEP-COMP (1-800-237-2667) or by writing to:

Investor Services American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUAL REPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1999 at no cost to shareholders. Please address requests for copies to:

Financial Reporting Division American Electric Power Service Corporation 26th Floor 1 Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK First Chicago Division, Equiserve P.O. Box 2500 Jersey City, NJ 07303-2500 Phone number: 1-800-328-6955

Indiana Michigan Power Service Area and the American Electric Power System lAKE trl I c tt I G A 8 MICH I GAN OHIO INDIANA WEST V I RG IN IA VI RG INIA KENTUCKY Indiana Michigan Power Co. area Other AEP operating companies'reas Q Major power plant TENNESSEE O~

Clg printed on recycled paper

ATTACHMENT 2 TO AEP:NRC:09090 INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1999

Indiana Michigan Power Co.

1999 Forecasted Internal Cash Flow 0 Millions Projected 1999 Net Income After Taxes 99.5 Less: Dividends 114.4 (14.9)

Ad'ustments:

Depreciation and Amortization 148.5 Deferred Operating Costs (86.2)

Deferred Federal Income Taxes and Investment Tax Credits 4.6 AFUDC (9.2)

Other (5.7)

Total Adjustments 52.0 Internal Cash Flow 37.1 Average Quarterly Cash Flow 9.3 Average Cash Balances and Short-Term Investments 2.9 Total 12.2 nukecf99.xls 5/14/99

'll

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