ML17332A723

Forwards Indiana Michigan Power Co Annual Rept for 1994 & Projected Cash Flow for 1995,per 10CFR50.71(b) & 10CFR140.21(e)

ML17332A723
Person / Time
Site:	Cook
Issue date:	03/31/1995
From:	Fitzpatrick E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909K, AEP:NRC:909K, NUDOCS 9504070317
Download: ML17332A723 (43)

Text

P R.ICBM.I RIDS PROCESSING "EY'ACCELERATED REGULATORY INFORMATION DISTRIBUTION SYSTEM (RIDS)

ACCESSION NBR:9504070317 DOC.DATE: 95/03/31 NOTARIZED: NO DOCKET g FACIL:50-315 Donald C. Cook Nuclear Power Plant, Unit 1, Indiana M 05000315 50-316 Donald C. Cook Nuclear Power Plant, Unit 2, Indiana M 05000316 AUTH. NAME AUTHOR AFFILIATION P FITZPATRICK,E. Indiana Michigan Power Co. (formerly Indiana & Michigan Ele RECIP.NAME RECIPIENT AFFILIATION Document Control Branch (Document Control Desk) R

SUBJECT:

Forwards Indiana Michigan Power Co annual rept for 1994 S projected cash flow for 1995,per 10CFR50.71(b) 10CFR140.21(e).

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TITLE: 50.71(b) Annual Financial Report NOTES RECIPIENT COPIES RECIPIENT COPIES ID CODE/NAME LTTR ENCL ID CODE/NAME LTTR ENCL PD3-1 LA 1 1 PD3-1 PD 1 1 HIC 1 1 INTE AL: FILE CENTER 0 1 1 EXTERNAL NRC PDR 1 1 D

0 C'

N NOTE TO ALL"RIDS" RECIPIENTS:

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indiana Michigan Power Company P.O. Box 16631 Columbus, OH 43216 Narch 31, 1995 AEP:NRC:0909K Docket Nos,: 50-315 50-316 U.'S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555 Gentlemen:

Donald C. Cook Nuclear Plant Units 1 and 2 FINANCIAL INFORMATION FOR INDIANA MICHIGAN POWER COMPANY Attachment 1 contains the Indiana Michigan Power Company's (16M) annual report for 1994. Attachment 2 contains a copy of 16M's projected cash flow for 1995. These reports are submitted pursuant to 10 CFR 50.71(b) and 10 CFR 140.21(e).

Sincerely, E. E. Fitzpa rick Vice President eh Attachments CC: A. A. Blind G. Charnoff J. B. Martin NFEM Section Chief NRC Resident Inspector - Bridgman J. R. Padgett 95040703i7 95033i PDR ADOCK 050003i5 PDR

ATTACHMENT 1 TO AEP:NRC:0909K INDIANA MICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1994

1994 Annual Report CONTENTS Background .

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

Dividends and Price Ranges of Cumulative Preferred Stock 31-32

NA MICHIGANPOWER COMPANY AND SUBSIDIARIES One Summit Square, p.O. Box 60, Fort Wayne, indiana 46801 BACKGROUND INDIANAMICHIGANPOWER COMPANY (the Company) is engaged in the generation, purchase, transmission and distribution of electric power. The Company serves approximately 531,000 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 and electric cooperatives. Approximately 82% of the Company's retail sales are in Indiana and 18% in Michigan. The principal industries served are primary metals, transportation equipment, fabricated metal products, electrical and electronic machinery, rubber and miscellaneous plastic products and chemicals and allied products.

The Company is a subsidiary of American Electric Power Company, Inc., and was organized under the laws of Indiana on February 21, 1925. 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 4,434 megawatts (mw) of generating capacity which includes 2,295 mw of coal-fired generation and the 2,110 mw Donald C. Cook Nuclear Plant. The generating plants and transmission facilities of the Company and certain other affiliated AEP System utility subsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission Agreement. Wholesale energy sales made by the Power Pool are allocated to the Pool members.

The other AEP System Pool members are: Appalachian Power Company, Columbus Southern Power Company, Kentucky Power Company and Ohio Power Company. The Company is also 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 Power Company, Illinois Power Company, Indianapolis Power 5. Light Company, Louisville Gas and Electric Company, Northern Indiana Public Service Company, PSI Energy Inc. and Richmond Power and Light Company, as well as Indiana-Kentucky Electric Corporation (a subsidiary of Ohio Valley Electric Corporation, an affiliate that is not a member of the AEP System) In addition, the Company is interconnected through the AEP System with

~

two other affiliated companies, Kingsport Power Company and Wheeling Power Company and with numerous unaffiliated utilities.

DIRECTORS Mark A. Bailey James J. Markowsky (b)

Peter J. DeMaria Richard C. Mange William N. D'Onofrio Albert H. Potter (c)

A. Joseph Dowd (a) Ronald E. Prater (d)

E. Linn Draper, Jr. David B. Synowiec (d)

William J Lhota~ Dale M. Trenary (c)

Gerald P. Maloney William E. Walters OFFICERS E. Linn Draper Jr. Gerald P. Maloney Chairman of the Board and Chief Executive Officer Vice President Richard C. Menge James J. Markowsky President and Chief Operating Officer Vice President Mark A. Bailey John F. DiLorenzo, Jr.

Vice President Secretary A. Alan Blind (e) Elio Bafile Site Vice President, Donald C. Cook Nuclear Plant Assistant Secretary and Assistant Treasurer Peter J. DeMaria Jeffrey D. Cross Vice President and Treasurer Assistant Secretary William N. D'Onofrio Carl J. Moos Vice President Assistant Secretary A. Joseph Dowd (a) John B. Shinnock Vice President Assistant Secretary Eugene E. Fitzpatrick Leonard V. Assante Vice President Assistant Treasurer William J. Lhota Bruce M. Barber Vice President Assistant Treasurer Gerald R. Knorr Assistant Treasurer As of January 1, 1995 the cttrrent directors and officer of Indiana Michigan Power Company were employees ol'American Electric power Service Corporation with nine exceptions: Messrs. Bafile, Bailey, Blind, D'Onofrio, Mange, Moos, Potter, Trenary and Wo(ters, who were employees of Indiana Michigan Power Company.

(el Ree/oned Notrernber 9O, 1994 (dl Reejtned Aprg 26, 1994 (bl Elected Jenrery 24, 1995 (el Elected htey 1, 1994 (cl Elected Afrri7 28, 1994

Selected Consolidated Financial Data I INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Year En D m ef 1 1 94 1992 1 91 (in thousands)

INCOME STATEMENTS DATA:

Operating Revenues $ 1,251,309 $ 1,202,643 $ 1,196,755 $ 1,225,867 $ 1,271,514 Operating Expenses ~12~7 ~272 ~10 ~12 ~9578 1 $ 77) ~2 Operating Income Nonoperating Income (Loss)

Income Before Interest Charges

~742 221,731 229,159

~24)209,920 209,686

~14 195,520 11 209,635

~721 227,289 223,568

~77 201,491 209,048 Interest Charges ~SJiSZ ~t56K ~KSBZ

'36,932 Net Income Preferred Stock Dividend Requirements Earnings Applicable to Common Stock 4 157,471 lllSSf 145 821

~14 4

129,313 22 115 088 ~108 123,948 15 417 531

~1417 4 121 515

~17 S

118,391 102 804 December 1 19 4 199 1992 1991 ~190 BALANCE SHEETS DATA: (in thousands)

Electric Utility Plant $ 4,269,306 $ 4,290,957 $ 4,266,480 $ 4,135,820 $ 4,066,227 Accumulated Depreciation and Amortization ~1~4 ~1714 29 ~1~14 ~12~14 1 421 2 5 Net Electric Utility Plant 42 609 366 ~2576 128 ~2635 042 42 614 471 2 644 942 Regulatory Assets 4 481 212 441 681 208 938 4 141 517 164 739 Total Assets 43 915 729 43 765 458 43 645 798 43 481 878 43 501 925 Common Stock and Paid-in Capital 791,095 791,517 782,741 782,741 782,741 Retained Earnings 21f165Q ~177 38 17~1 fff9 243 ~1~4 Total Common Shareowner's Equity Sl 007 753 4 969 155 4 954 050 4 951 984 4 933 149 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption 52,000 S 87,000 197,000 S 197,000 S 197,000 Subject to Mandatory Redemption (a) ~1~00 10~0 Total Cumulative Preferred Stock 4 187 000 ~187 000 4 197 000 ~$ 197 00 197 000 Long-term Debt (a) ~1069 887 ~1073 154 Sl 211 623 Sl 130 709 Sl 133 833 Obligations Under Capital Leases (a) 4 152 589 4 98 753 126 689 102 985 133 447 Total Capitalization and Liabilities 43 915 729 ~3765 458 ~3645 798 43 481 878 ~3501 925 lel Including portion due within one yeer.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Results of Operations Net Income Increases Net income increased 21.8% to $ 157 million in Although wholesale energy sales declined 35%

1994 mainly due to a retail base rate increase in in 1994, wholesale revenues declined only 13%

the Company's Indiana jurisdiction, reduced interest reflecting the continuing effect of fixed capacity expense due to the retirement of long-term debt, charges recovered from the AEP System Power the adoption of Statement of Financial Accounting Pool (Power Pool), which are unrelated to the Standards No. 109, Accounting for Income Taxes amount of energy actually delivered, and an (SFAS 109) in 1993 and the retirement of a gener- increase in take-or-pay capacity reservation charges ating plant. The increase in net income in 1993 of collected from unaffiliated utilities. The decline in 4.3% was the result of lower interest expense due wholesale energy sales reflects the decrease in to the retirement of long-term debt and the return energy available for delivery to the Power Pool due to service of the Company's nuclear units from to the scheduled refueling and maintenance outag-refueling and maintenance outages completed in es at both of the Company's nuclear units in 1994 1992. and lower energy sales by the Power Pool due to mild weather throughout most of 1994. While Operating Revenues Increase and Energy Sales severe weather in January 1994 and hot June Decline weather increased the Power Pool's short-term wholesale sales in those months, the mild weather Operating revenues increased 4% in 1994 and a throughout the remainder of 1994, combined with minor amount in 1993. The changes in revenues increased competition in the wholesale market, can be analyzed as follows: reduced short-term sales for the year.

Increase (Decrease)

From Previous Year Although retail energy sales increased 5% in dollars in millions 1994 1993 1993, retail revenues decreased 4% reflecting the operation of fuel and power supply recovery mech-Retail: anisms due to the increased availability in 1993 of Price variance $ 69.8 $ (75.1) the lower cost nuclear units. Under the retail juris-Volume variance 30.5 40.3 100.3 12.9 ~34.8) (4.3) dictional fuel clauses, revenues were accrued in Mholesale: 1992 for future recovery of higher cost replace-Price variance 90.7 (137.2) ment power during the nuclear outages. In 1993, Volume variance J~52.0)()2.0) 142.7) 172.7 35.5 with the nuclear units returned to full service, the 9.6 Other Operating Revenues 0.4 5.2 accruals for higher cost coal based replacement Total ~40.7 4.0 ~5.9 0.5 power ceased. The increase in retail energy sales in 1993 reflects continued growth in industrial Retail operating revenues increased 13% during customer usage, a return to normal weather and 1994 reflecting a $ 34.7 million annual rate increase growth in the number of customers in all retail in the Indiana jurisdiction, increased decommis- classes.

sioning expense recoveries in the Michigan jurisdic-tion, the operation of the retail fuel and power Wholesale revenues increased 10% and whole-sale energy sales increased 47% in 1993 due supply cost recovery mechanisms and a 4% in-crease in energy sales. The increase in retail primarily to the increased availability of the nuclear energy sales in 1994 resulted from the growth in generating capacity making more energy available the number of customers served in all retail cus- for sale to the Power Pool and increased sales by tomer classes and increased usage by industrial and the Power Pool to unaffiliated utilities which the commercial customers. Energy sales to residential Company shares as a member of the Pool.

customers remained constant in 1994 as mild weather during most of the year offset the effect of the severe weather in January and the unsea-sonably warm weather in May and June.

IIVDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES rate recovery and the accrual of employee sever-ance benefits resulting from the closing of the Operating Expenses Increase Breed Plant and the recommendations from an organizational review study. The 1993 increase Changes in the components of operating ex- also reflected increased nuclear costs including penses were as follows: decommissioning accruals and other postretirement Increase (Decrease) benefit accruals.

From Previous Year dollars in millions 1994 1993 The increase in taxes other than federal income taxes in 1993 was primarily due to a substantial Fuel increase in Indiana supplemental net income tax.

Purchased Power In 1992 Indiana supplemental net income tax was Other Operation Maintenance significantly reduced by the deduction of nuclear Depreciation and refueling and maintenance outage costs. There Amortization (2.6) (1.8) 5.4 4.1 were no refueling outages in 1993.

Amortization of Rockport Plant Unit 1 Phase-in Plan Oeferrals (0.7) (4.0) Federal income taxes attributable to operations Taxes Other Than increased in both periods due to increased pre-tax Federal Income Taxes 3.3 4.8 5.7 9.2 operating income.

Federal Income Taxes 6.4 18.4 9.2 36.1 Total ~36.9 3.7 ~8.5) (0.9)

Nonoperating Income increases and Financing Fuel expense declined in 1994 due to a signifi- Costs Decline cant reduction in nuclear generation, partially offset by a 6% increase in fossil generation. Nuclear gen- Nonoperating income increased in 1994 reflect-eration declined by 43% due to the scheduled ing the favorable tax effect of the Breed Plant refueling outages at both nuclear units. The in- closing and the effect of the recordation in 1993 of crease in 1993 fuel expense was mainly attribut- the unfavorable effect of adopting SFAS 109 for able to a significant increase in nuclear generation nonutility assets and liabilities. The decline in and increased fossil generation, partially offset by nonoperating income in 1993 was due to the a decrease in the average cost of fuel. Refueling adoption of the new tax accounting standard, the and maintenance outages in 1992 coupled with the effect of interest income recorded in 1992 from the absence of outages in 1993 accounted for the settlement of prior years'ederal income tax audits increase in nuclear generation. and the reversal in 1992 of a previously recorded provision for a loss as a result of the successful The increase in purchased power expense in settlement of a coal royalty dispute in the state of 1994 reflects increased energy receipts from the Utah.

Power Pool to replace the nuclear power that was not available due to the scheduled nuclear refueling Interest charges declined in both 1994 and and maintenance outages in 1994 and increased 1993 due to debt repayments and a refinancing purchases from unaffiliated utilities for immediate program which lowered interest rates. In 1994 resale to other unaffiliated utilities. Purchased $ 10 million of long-term bonds were retired and power expense declined in 1993 due to reduced $ 90 million were refinanced. During 1993 $ 142 energy receipts from the Power Pool because of million of long-term bonds were retired and $ 150 the increased availability of both nuclear units and million of bonds and $ 97 million of installment decreased purchases from AEP Generating Compa- purchase contracts were refinanced at lower rates.

ny (AEGCo), an affiliate that is not a member of the Power Pool. In 1993 energy purchased from Construction Spending AEGCo was reduced since both of AEGCo's gener-ating units had outages for planned boiler main- Gross plant and property additions were $ 212 tenance and repairs. million in 1994 and $ 125 million in 1993. Manage-ment estimates construction expenditures for the Other operation expense increased in 1994 due next three years to be $ 393 million including to regulator approved increases in accruals of expenditures necessary to meet the requirements additional nuclear decommissioning expense and of the Clean Air Act Amendments of 1990. The other postretirement benefits commensurate with funds for construction of new facilities and im-

provement of existing facilities can come from a build and operate new generating plant. The combination of internally generated funds, short- primary competitive factors have been price, term and long-term borrowings and investments in reliability of service and the ability of customers to common equity by the Company's parent, Ameri- utilize sources of energy other than electric power.

can Electric Power Co., Inc. (AEP Co., Inc.). The lack of independent power producers and However, all of the construction expenditures for significant self generation in our service territory the next three years are expected to be financed evidences our past ability to compete. With re-internally. These estimated construction expendi- spect to alternative energy sources, management tures do not include any major new generating believes that the convenience and versatility of capacity. electricity and reliability of our service coupled with the limited ability of customers to substitute other Capital Resources energy sources for electric power have placed us in a favorable competitive position. However, we When necessary the Company generally issues continue to work to improve the competitiveness, short-term debt to provide for interim financing of effectiveness and reliability of our product. The capital expenditures that exceed internally generat- Company, for example, markets high-efficiency ed funds. At December 31, 1994, unused short- heat pumps and off-peak storage water heaters term lines of credit shared with other AEP System which make electricity competitive with natural gas companies of $ 558 million were available. A for space and water heating.

charter provision limits the Company's short-term borrowings to $ 130 million. Periodic reductions of Competition in the wholesale market, that is the outstanding short-term debt are made through sale of bulk power to other public and municipal issuances of long-term debt and preferred stock utilities, is not new and has been increasing for a and through additional capital contributions by the number of years. This is particularly true in the parent company. short-teim market. The National Energy Policy Act of 1992 (the Energy Act) facilitated competition in The Company recently received regulatory the short and long-term wholesale market since, approval to issue up to $ 160 million of long-term among other things, it authorized the Federal debt. Management expects to use the proceeds to Energy Regulatory Commission (FERC) to order retire short-term debt, to refinance higher cost and transmission access for wholesale transactions.

maturing long-term debt and to reacquire cumula- The principal factors in competing for wholesale tive preferred stock. sales are price including fuel costs, availability of capacity, transmission capability and cost, and The Company presently exceeds all minimum reliability of service. Management believes that coverage requirements for issuance of preferred over the years the Company has generally main-stock and long-term debt. At December 31, 1994, tained a favorable competitive position in these long-term debt and preferred stock coverage ratios factors. However, due to the recent availability of were 5.08 and 2.74, respectively. additional capacity of other utilities and reduced fuel prices, price competition, particularly in the Competition short-term wholesale market, has been, and is expected to be important in the future.

In exchange for the exclusive right to provide electric generation, transmission and distribution With the passage of the Energy Act, the poten-services within a designated service territory at tial for retail wheeling, i.e., competition for retail cost-based regulated prices that provide the oppor- sales, is getting considerable attention. While the tunity to earn a regulator-determined reasonable Energy Act gave the FERC broad authority to rate of return on shareholders'quity, electric mandate transmission access in the wholesale utilities are obligated to serve all customers within market, it prohibits the FERC from ordering retail such service territories. While the Company is a wheeling. A number of state legislatures and state regulated monopoly, we have competed historically regulatory agencies have begun to study retail with self-generation and with distributors of alter- wheeling with encouragement from major industrial native sources of energy, such as natural gas, fuel customers.

oil and coal, within our service area. In recent years regulated electric utilities have also competed If it occurs, increased competition may require with independent power producers for the right to the resolution of some complex issues, such as

INDIANAMICHIGANPOWER COMPANY I AND SUBSIDIARIES stranded investment and the obligation to serve. Environmental Concerns When a customer leaves a utility system there is an Clean Air Act issue of who pays for regulatory assets, plant investment and commitments that are no longer The Clean Air Act Amendments of 1990 needed. If a customer leaves its native electric (CAAA) require, among other things, substantial supplier and later decides to return, the issue of reductions in sulfur dioxide and nitrogen oxide whether the original local utility has an obligation to emissions from electric generating plants. The first serve the returning customer must also be ad- phase of reductions in sulfur dioxide emissions dressed. If not recovered directly from customers (Phase I) began on January 1, 1995 and the sec-that choose another supplier and/or from the ond, more restrictive phase (Phase II) begins on remaining regulated customers, the Company, like January 1, 2000. The law also establishes a all electric utilities, will be required to address permanent nationwide cap on sulfur dioxide emis-stranded investment losses that could result from sions after 1999.

any future loss of customers or reduced pricing from head-to-head competition. Management Two of the Company's generating units, Tan-intends to seek recovery of any stranded invest- ners Creek Unit 4 and the Breed Plant, were affect-ment, including regulatory assets, as an appropriate ed by the first phase of the CAAA. Tanners Creek recovery of previously approved cost of service. Unit 4 complied by fuel switching with minimal capital cost. Management decided to close the Activity-based budgeting and cost management 325 megawatt Breed Plant in 1994, due to its techniques are being currently developed to enable design, age and the cost of complying with the management to cost logical work activities and CAAA. The closing of the Breed Plant did not services. By examining our operations by logical adversely affect results of operations.

work units, the cost of all major activities can be better controlled, identified and evaluated to prop- Phase II of the CAAA will require further compli-erly price our products and to eliminate unneces- ance actions and additional costs. Management sary activities and their cost. Management believes intends to seek timely recovery of all CAAA costs.

these activities will enhance our ability to compete.

Global Climate Change The development of tools and training to enable management to better manage the costs of opera- Concern about global climate change, or "the tions are only one of the options currently being greenhouse effect" has been the focus of intensive pursued. In 1994 the Company's management debate within the United States and around the team has been: world. Much of the uncertainty about what effects Reviewing and streamlining operations and greenhouse gas concentrations will have on the staffing, global climate results from a myriad of factors that o Reducing layers of supervision, affect climate. Based on the terms of a 1992 Expanding customer relations and service United Nations treaty that pledged the United activities, States to reduce greenhouse gas emissions, the o Expanding its ability to help customers adopt Clinton Administration developed a voluntary plan new electro-technologies to reduce their to reduce greenhouse gas emissions to 1990 levels usage of electricity, and by the year 2000. As part of this plan, the AEP Expanding strategic planning and manage- System is participating with the U.S. Department of ment training activities. Energy (DOE) and other electric utility companies in a climate change program to limit future green-Management is committed to maintaining and house gas emissions.

enhancing our business. Management is moving in "new directions" to maintain and improve our The climate change program applies a policy of competitive position. Whether competition ex- proactive environmental stewardship, whereby pands or not, these efforts should serve to lower actions are taken that make economic and environ-cost of service and rates and improve sales through mental sense on their own merits, irrespective of economic development in our service territory. the uncertain threat of global climate change. The plan includes energy conservation programs, improvements in fossil generation efficiency, increased use of nuclear capacity and forest man-

agement activities. However, should it be deter- significant effect on results of operations. 18M mined necessary to enact significant new measures also has been named as a PRP at one Illinois site to control the burning of coal, the cost of such and has received an information request for one measures if not recovered from ratepayers, could Indiana site under similar state clean-up laws.

adversely impact results of operations and possibly financial condition. In all instances where the Company has been named a PRP or defendant, the disposal or recy-EMF cling activity was in accordance with applicable laws and regulations. However, Superfund does The potential for electric and magnetic fields not recognize compliance as a defense, but impos-(EMF) from transmission and distribution facilities, es strict liability on parties who fall within its broad to adversely affect the public health is being exten- statutory categories. As a result, AEP has institut-sively researched. The AEP System continues to ed a number of Systemwide policies that have support research to help determine the extent, if raised the standard of care by going beyond regula-any, to which EMF may adversely impact public tory requirements where appropriate.

health. Our concern is that new laws imposing EMF limits may be passed or new regulations While the potential liability for each site must be promulgated without sufficient scientific study and evaluated separately, several general statements evidence to support them. As long as there is can be made regarding such potential liability. The uncertainty about EMF, the Company and other disposal. by the Company at a particular site is electric utilities will have difficulty finding accept- often unsubstantiated; the quantity of material able sites for their facilities, which could hamper disposed of at a site was generally small; and the economic growth within our service area. If the nature of the material generally disposed of was present energy delivery system must be changed non-hazardous. Typically, the Company is one of because of EMF concerns, or if the courts conclude many parties named PRPs for a site and, although that EMF exposure harms individuals and that liability is joint and several, at least some of the utilities are liable for damages, then the Company's other parties are financially sound enterprises.

results of operations and financial condition could Therefore, present estimates do not anticipate be adversely affected, unless the costs can be material clean-up costs for identified disposal sites.

recovered from ratepayers. However, if for unknown reasons, significant costs are incurred for cleanup, results of operations and Hazardous Material possibly financial condition would be adversely affected unless the costs can by recovered from By-products from the generation of electricity insurance proceeds and/or with regulatory approval include materials such as ash, slag, sludge, low- from ratepayers.

level radioactive waste and spent nuclear fuel. In addition, generating plants and transmission and Nuclear Cost distribution facilities have used asbestos, polychlor-inated biphenyls (PCBs) and other hazardous and The cost to operate and maintain the two-unit non-hazardous materials. The Company is current- Donald C. Cook Nuclear Plant is impacted by Nu-ly incurring costs to safely store and dispose of clear Regulatory Commission (NRC) requirements such substances, and additional costs could be and the normal aging of the plant (Unit 1 began incurred to comply with new laws and regulations commercial operation in 1975 and Unit 2 in 1978).

if enacted. In addition, the cost to decommission the plant is affected by NRC regulations and the DOE's Spent The Comprehensive Environmental Response Nuclear Fuel (SNF) disposal program. Studies Compensation and Liability Act (Superfund) ad- completed in 1994 estimate the cost to decommis-dresses clean-up of hazardous substance disposal sion the plant and dispose of low level nuclear sites and authorizes the United States Environmen- waste accumulation to range from $ 634 million to tal Protection Agency (Federal EPA) to administer $ 988 million in 1993 dollars. By law the Company the clean-up programs. The Company has been participates in the DOE's SNF disposal program named by the Federal EPA as a "potentially respon- which is described in Note 4 of the Notes to Con-sible party" (PRP) for eight sites and has received solidated Financial Statements. Decommissioning information requests for three other sites. For four costs and spent nuclear fuel disposal costs are of the PRP sites, liability has been settled with no being recovered from ratepayers. In 1993 the

II INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Indiana and the Michigan commissions approved In 1994 the Financial Accounting Standards higher levels of recovery so that the amount cur- Board (FASB) added Accounting for Nuclear De-rently being recovered is at least at the lower end commissioning Liabilities to its agenda. Among the of the range in the prior decommissioning study. topics to be studied by the FASB is the question of To date $ 212 million in decommissioning cost has when future decommissioning liabilities should be been recovered and accrued. Management intends recognized. The Company and the electric utility to seek recovery through the rate-making process industry accrue such costs over the service life of of changes in the estimate of decommissioning their nuclear facilities as recovered in rates. A new costs over the remaining plant life. requirement from the FASB could cause the annual provisions for decommissioning to increase should Nuclear operations are continually reviewed for the estimate of the remaining unaccrued decommis-ways to lessen the growth in operation, mainte- sioning costs be greater than the regulators'l-nance and decommissioning costs. In 1994 Cook lowed recovery level. Management believes that Plant achieved a superior rating from the Institute the industry's life of the plant accrual accounting of Nuclear Power Operations, a nuclear industry method is appropriate and should be accepted by oversight group, and received improved NRC the FASB. Until the FASB completes its study and performance ratings. Additionally, costs related to reaches a conclusion, the impact, if any, on results nuclear refueling outages at the Cook Plant have of operations and financial condition cannot be been reduced significantly in the last two years. determined.

The operation of a nuclear facility involves Litigation special risks, potential liabilities, and specific regulatory and safety requirements. Should a The Company is involved in a number of legal nuclear incident occur at any nuclear power plant proceedings and claims. While we are unable to facility in the United States, the resultant liability predict the outcome of such litigation, it is not could be substantial. By agreement I%M is partially expected that the resolution of these matters will liable together with all other electric utility compa- have a material adverse effect on financial condi-nies that own nuclear generating units for a nuclear tion. Information about these matters can be found power plant incident. Should nuclear losses or in the footnotes to the financial statements.

liabilities be underinsured or exceed accumulated funds, or should recovery through regulated rates Effects of Inflation be denied, results of operations and financial condition would be negatively affected. Specific Inflation affects the cost of replacing utility plant information about nuclear risk management and and the cost of operating and maintaining such potential liabilities is discussed in Note 4 of the plant. The rate-making process generally limits Notes to Consolidated Financial Statements. recovery to the historical cost of assets resulting in economic losses when inflation effects are not recovered from customers on a timely basis.

However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.

INDEPENDENT AUDITORS'EPORT To the Shareowners and Board of Directors of Indiana Michigan Power Company:

We have audited the accompanying consolidated balance sheets of Indiana Michigan Power Company and its subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Indiana Michigan Power Company and its subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP Columbus, Ohio February 21, 1995 10

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Income Y rEn dD emb r31 1994 1993 1 92 (in thousands)

OPERATING REVENUES ~12 ~10 ~120~24 ~11 ~7 OPERATING EXPENSES:

Fuel 201,739 220,206 193,830 Purchased Power 131,234 108,274 180,365 Other Operation 293,024 264,543 251,897 Maintenance 139,423 142,637 137,787 Depreciation and Amortization 136,244 138,794 133,365 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 15,644 15,644 16,303 Taxes Other Than Federal Income Taxes 71,191 67,918 62,189 Federal Income Taxes 41 079 34 7(47 2!~4 Total Operating Expenses 1 029 578 992 723 ~1 1~2 OPERATING INCOME 221,731 209,920 195,520 NONOPERATING INCOME (LOSS) 7 428 ~234 14 11 INCOME BEFORE INTEREST CHARGES 229,159 209,686 209,635 INTEREST CHARGES ~873 ~~7 NET INCOME 157,471 129,313 123,948 PREFERRED STOCK DIVIDEND REQUIREMENTS ~11 85 14 225 ~14 7 EARNINGS APPLICABLE TO COMMON STOCK ~146 821 4 115 088 ~108 531 See Notes to Consolidated Rnanoial Statements.

11

Consolidated Balance Sheets De emb r 31 1 994 1 993 (in thousands)

ASSETS ELECTRIC UTILITY PLANT:

Production $ 2,494,834 $ 2,602,527 Transmission 849,920 839,198 Distribution 644,720 608,752 General (including nuclear fuel) 204,909 1 52,470 Construction Work in Progress ~74 92 ~88 01 Total Electric Utility Plant 4,269,306 4,290,957 Accumulated Depreciation and Amortization ~159 40 1 714 829 NET ELECTRIC UTILITY PLANT 2 609 366 ~2 57 12 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 341 0 3 0671 OTHER PROPERTY AND INVESTMENTS 127 424 131 788 CURRENT ASSETS:

Cash and Cash Equivalents 9,907 3,752 Accounts Receivable:

Customers 74,491 67,246 Affiliated Companies 24,848 24,507 Miscellaneous 32,714 30,087 Allowance for Uncollectible Accounts (121) (504)

Fuel - at average cost 35,802 34,476 Materials and Supplies - at average cost 59,897 57,800 Accrued Utility Revenues 40,582 34,642 Prepayments 8 414 ~12 04 TOTAL CURRENT ASSETS 286 534 264 049 REGULATORY ASSETS 4II1 212 ~441 1 DEFERRED CHARGES ~71 4 ~11 41 TOTAL $3 915 729 $3 765 458 See Notes to Consolidoted Rnenciel Stotements.

12

IND MICHIGANPOWER COMPANY AND SUBSIDIARIES Dec mbr 1 94 ~1 (in thousands)

CAPITALIZATIONAND LIABILITIES CAPITALIZATION:

Common Stock - No Par Value:

Authorized - 2,500,000 Shares Outstanding - 1,400,000 Shares 56,584 $ 56,584 Paid-in Capital 734,511 734,933 Retained Earnings 21~$ 17~7 Total Common Shareholder's Equity 1,007,763 969,155 Cumulative Preferred Stock:

Not Subject to Mandatory Redemption 62,000 87,000 Subject to Mandatory Redemption 135,000 100,000 Long-term Debt 929 887 ~107 1 4 TOTAL CAPITALIZATION 2124 4 2 22 309 OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning 211,963 169,706 Other 17i~4 ~11 4 1 TOTAL OTHER NONCURRENT LIABILITIES ~2'~17 CURRENT LIABILITIES:

Long-term Debt Due Within One Year 140,000 Short-term Debt - Commercial Paper 50,600 50,075 Accounts Payable - General 40,417 40,437

'Accounts Payable - Affiliated Companies 22,720 17,481 Taxes Accrued 63,621 54,473 Interest Accrued 19,436 18,894 Obligations Under Capital Leases 39,003 20,585 Other ~7821 7!~7 TOTAL CURRENT LIABILITIES 46,'~1 21 12 DEFERRED FEDERAL INCOME TAXES 5tg 6~4 553 920 DEFERRED INVESTMENT TAX CREDITS 171~ ~18 i ttg2 DEFERRED GAIN ON SALE AND LEASEBACK-ROCKPORT PLANT UNIT 2 ~24~1 211 446 DEFERRED CREDITS 1 242 COMMITMENTS AND CONTINGENCIES (Note 4)

TOTAL $3 915 729 $3 765 458 13

7 Consolidated Statements of Cash Flows Ye rEn D em

~1 (in thousands)

OPERATING ACTIVITIES:

Net Income S 157,471 S 129,313 S 123,948 Adjustments for Noncash Items:

Depreciation and Amortization 146,966 148,270 141,453 Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals 15,644 15,644 16,303 Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) (18,779) 33,827 (47,200)

Deferred Federal Income Taxes (17,049) (49,905) 29,897 Deferred Investment Tax Credits (13,877) (8,543) (9,673)

Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net) (10,596) 13,102 (7,432)

Fuel, Materials and Supplies (3,423) 14,938 1,018 Accrued Utility Revenues (5,940) 43,913 (41,068)

Accounts Payable 5,219 8,233 (15,088)

Taxes Accrued 9,148 38,644 4,514 Other (net) ~11 444 ~17 64 ~16 448 Net Cash Flows From Operating Activities ~2I~4 ~71~72 1 224 INVESTING ACTIVITIES:

Construction Expenditures Proceeds from Sales of Property and Other Net Cash Flows Used For Investing Activities (118,094)

~203 116 056 (108,867)

~10 482 8 ~0 (125,908)

~125 00 FINANCING ACTIVITIES:

Capital Contributions from Parent Company 10,000 Issuance of Cumulative Preferred Stock 34,618 98,776 Issuance of Long-term Debt 89,221 243,426 271,722 Retirement of Cumulative Preferred Stock (35,798) (112,300)

Retirement of Long-term Debt (101,833) (392,093) (203,185)

Change in Short-term Debt (net) 525 5,875 (6,750)

Dividends Paid on Common Stock (106,608) (108,696) (106,465)

Dividends Paid on Cumulative Preferred Stock ~112 4 ~141 7 Net Cash Flows Used For Financing Activities 1 ~29/ ~27 I~97) ~Q 0K)

Net Increase (Decrease) in Cash and Cash Equivalents 6,155 (3,707) (4,8761 Cash and Cash Equivalents January 1 ~752 ~745 ~123 5 Cash and Cash Equivalents December 31 4 9 907 4 3752 $ 7 459 Soo hates to Consolidated Rnanoial Statements.

14

I f~

INDIANAMICHIGANPOWER COMPANY AND SUBSIDIARIES Consolidated Statements of Retained Earnings Ye rEn e D mber31 1991 1 92 (in thousands)

Retained Earnings January 1 $ 177,638 $ 171,309 $ 169,243 Net Income 'I 57 471 ~I2 13 ~12 94

'1~3~19 ~30 22 ~21 91 Deductions:

Cash Dividends Declared:

Common Stock 106,608 108,696 106,465 Cumulative Preferred Stock:

4-1/8% Series 495 495 495 4.56% Series 273 273 273 4.12% Series 165 165 165 5.90% Series 2,360 374 6-1/4% Series 1,875 161 6.30% Series 1,978 6-7/8% Series 2,063 1,799 7.08% Series 2,124 2,124 2,124 7.76% Series 317 2,716 2,716 8.68% Series 2,517 2,604

$ 2.15 Series 3,001 3,440

$ 2.25 Series 2ZdK Total Cash Dividends Declared 118,258 122,921 121,882 Capital Stock Expense 193 63 Total Deductions 11 451 122 4 ~121 82 Retained Earnings December 31 $ 2'16 658 $ 177 638 $ 171 309 See Notes to Consolidated Pinanoial Statements.

15

NOTES TO CONSOLIDATED FINANCIALSTATEMENTS

1. SIGNIFICANT ACCOUNTING POLICIES: Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Organization Certain Types of Regulation, regulatory assets and liabilities are recorded and represent regulator-Indiana Michigan Power Company (the Company approved deferred expenses or revenues, respec-or IS.M) is a wholly-owned subsidiary of American tively, resulting from the rate-making process.

Electric Power Company, Inc. (AEP Co., Inc.), a Such deferrals are amortized commensurate with public utility holding company. The Company is their inclusion in rates (revenues).

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

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

mining operations. Blackhawk Coal Company cur-rently leases and subleases portions of its Utah coal Allowance for Funds Used During Construction rights, land and related mining equipment to unaffil- (AFUDCj iated companies. Price River Coal Company, which owns no land or mineral rights, is inactive. AFUDC is a noncash nonoperating income item that is recovered with regulator approval over the Regulation service life of utility plant through depreciation and represents the estimated cost of borrowed and As a member of the AEP System, IS.M is subject equity funds used to finance construction projects.

to regulation by the Securities and Exchange Com- The average rates used to accrue AFUDC were mission (SEC) under the Public Utility Holding Com- Se0% in 1994, 8.75% in 1993 and 9.25% in'1992 pany Act of 1935 (1935 Act). Retail rates are and the amounts of AFUDC accrued were $ 3.4 regulated by the Indiana UtilityRegulatory Commis- million, $ 1.7 million and $ 3.8 million in 1994, sion (IURC) and the Michigan Public Service Com- 1993 and 1992, respectively.

mission (MPSC) The Federal Energy Regulatory

~

Commission (FERC) regulates wholesale rates. Depreciation and Amortization Principles of Consolidation Depreciation is provided on a straight-line basis over the estimated useful lives of utility plant and The consolidated financial statements include is calculated largely through the use of composite I'M and its wholly-owned subsidiaries. Significant rates by functional class as follows:

intercompany items are eliminated in consolidation.

Functional Class Composite Basis of Accounting ~of Pro ere Annual Rates Production:

As a cost-based rate-regulated entity, IRM's Steam-Nuclear 3.4X financial statements reflect the actions of regula- Steam-Fossil-Fired 4.3X tors that result in the recognition of revenues and Hydroelectric-Conventional 3.0X Transmission 1.9X expenses in different time periods than enterprises Oistribution 4. 2/e that are not rate regulated. In accordance with General 3.8X 16

Amounts to be used for removal of non-nuclear i IIVDIAIVAMICHIGANPOWER COMPANY Investment Tax Credits AND SUBSIDIARIES plant are presently recovered through depreciation charges included in rates. The accounting and Based on directives of regulatory commissions, rate-making treatment afforded nuclear decommis- the Company reflected investment tax credits in sioning costs and nuclear fuel disposal costs are rates on a deferral basis. Commensurate with rate discussed in Note 4. treatment deferred investment tax credits are being amortized over the life of the related plant invest-Cash and Cash Equivalents ment. The Company's policy with regard to invest-ment tax credits for non-utility property was to Cash and cash equivalents include temporary practice the flow-through method of accounting.

cash investments with original maturities of three months or less. Debt and Preferred Stock Operating Revenues Gains and losses on reacquired debt are deferred and amortized over the remaining term of the Revenues include the accrual of electricity con- reacquired debt in accordance with rate-making sumed but unbilled at month-end as well as billed treatment. If the debt is refinanced the reacquisi-revenues. tion costs are deferred and amortized over the term of the replacement debt commensurate with their Fuel Costs recovery in rates.

Fuel costs are matched with revenues in accor- Debt discount or premium and debt issuance dance with rate commission orders. Revenues are expenses are amortized over the term of the related accrued related to unrecovered fuel in both retail debt, with the amortization included in interest jurisdictions and for replacement power costs in the charges.

Michigan jurisdiction until approved for billing. If the Company's earnings exceed the allowed return Redemption premiums paid to reacquire preferred in the Indiana jurisdiction, the fuel clause mecha- stock are deferred and amortized in accordance nism provides for the refunding of the excess with rate-making treatment. The excess of par earnings to ratepayers. Wholesale jurisdictional value over costs of preferred stock reacquired to fuel cost changes are expensed and billed as meet sinking fund requirements is credited to paid-incurred. in capital.

Levelization of Nuclear Refueling Outage Costs Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds Incremental operation and maintenance costs associated with refueling outages at the Donald C. Investments held in trust funds for decommis-Cook Nuclear Plant (Cook Plant) are deferred for sioning nuclear facilities and for the disposal of amortization over the period (generally eighteen spent nuclear fuel are recorded at market value months) beginning with the commencement of an effective January 1, 1994. Previously such invest-outage until the beginning of the next outage. ments were recorded at cost. Adjustments for unrealized gains and losses to the carrying value of Income Taxes trust fund investments are not reflected in equity due to the rate-making process. Instead the unreal-The Company follows the liability method of ized gains and losses are recorded as regulatory accounting for income taxes as prescribed by SFAS assets and liabilities.

109, Accounting for Income Taxes. Under the liability method, deferred income taxes are provided Other Property and Investments for all temporary differences between book cost and tax basis of assets and liabilities which will Other property and investments are stated at result in a future tax consequence. Where the cost.

flow-through method of accounting for temporary differences is reflected in rates, regulatory assets and liabilities are recorded in accordance with SFAS 71 ~

17

8 6 Reclassifications 3. RATE MATTERS:

Certain prior-period amounts were reclassified to Unaffiliated Coal and Affiliated Transportation Cost conform with current-period presentation. Recovery In October 1993, the FERC denied a request by

2. EFFECTS OF REGULATION AND PHASE-IN a wholesale customer seeking rehearing of a PLANS: February 1993 order. The order concerned the reasonableness of coal costs from an unaffiliated The consolidated financial statements include supplier who leases a Utah mining operation from assets and liabilities recorded in accordance with the Company and affiliated coal transportation regulatory actions to match expenses and revenues charges. The February order reversed an adminis-in cost-based rates. Regulatory assets are expect- trative law judge's decision and dismissed the ed to be recovered in future periods through the complaint. The wholesale customer appealed the rate-making process and regulatory liabilities are October order to the U.S. Court of Appeals. It is expected to reduce future rate recoveries. The not anticipated that the ultimate resolution of this Company's regulatory assets and liabilities are matter will have a material adverse impact on comprised of the following: results of operations.

December 31 1994 1993 4. COIVIIVIITMENTSAND CONTINGENCIES:

(in thousands)

Regulatory Assets:

Amounts Oue From Customers for Construction and Other Commitments Future Federal Income Taxes $ 313,731 $ 286,948 Department of Energy Substantial construction commitments have been Decontamination and Decormissioning Assessment 51,896 37,086 made. Such commitments do not include any Rate Phase-in Plan Deferrals 43,159 58,803 expenditures for new generating capacity. The Nuclear Refueling aggregate construction program expenditures for Outage Cost Levelization 32,151 13,372 1995-1997 are estimated to be $ 393 million.

Unamortized Loss On Reacquired Debt 18,472 17,251 Other 21 803 28 221 Long-term fuel supply contracts contain clauses Total Regulatory Assets ~482 212 ~aat 681 that provide for periodic price adjustments. The retail jurisdictions have fuel clause mechanisms that Regulatory Liabilities:

Deferred Investment Tax Credits $ 171,688 $ 186,032 provide for recovery of changes in the cost of fuel Other Regulatory Liabilities* 350 158 with the regulators'eview and approval. The Total Regulatory tiaallltlea ~272 038 ~286 190 contracts are for various terms, the longest of

• Included in Deferred Credits on Consolidated Balance which extends to 2014, and contain various claus-Sheets. es that would release the Company from its obliga-tion under certain force majeure conditions.

Rockport Plant consists of two 1,300 megawatt (mw) coal-fired units. I(AM and AEP Generating Unit Power Agreements Company (AEGCo), an affiliate, each own 50% of one unit (Rockport 1) and each lease a 50% inter- The Company is committed under unit power est in the other unit (Rockport 2) from unaffiliated agreements to purchase 70% of AEGCo's 1,300 lessors under an operating lease. The gain on the mw Rockport Plant capacity unless it is sold to sale and leaseback of Rockport 2 was deferred and unaffiliated utilities. AEGCo has one long-term is being amortized, with related taxes, over the contract with an unaffiliated utility that expires in initial lease term which expires in 2022. 1999 for 455 mw of Rockport Plant capacity.

Rate phase-in plans in the Company's Indiana The Company sells under contract up to 250 mw and FERC jurisdictions for its share of Rockport 1 of Rockport Plant capacity to an unaffiliated utility.

provide for the recovery and straight-line amortiza- The contract expires in 2009.

tion through 1997 of prior-year deferrals.

18

NDIANA MICHIGANPOWER COMPANY AND SIJBSIDIA RIES Litigation Other Environmental Matters An appeal to the Indiana Court of Appeals by a The Company and its subsidiaries are regulated local distribution utility of a 1992 DeKalb County by federal, state and local authorities with respect Circuit Court of Indiana decision is pending. Oral to air and water quality and other environmental arguments before the Indiana Court of Appeals matters. Local authorities also regulate zoning.

were held in January 1995. The circuit court had The generation of electricity produces non-haz-dismissed the case filed under a provision of Indi- ardous and hazardous by-products. Asbestos, ana law that allows the local distribution utility to polychlorinated biphenyls (PCBs) and other hazard-seek damages equal to the gross revenues received ous materials have been used in the generating by the Company for rendering service in the desig- plants and transmission/distribution facilities.

nated service territory of the local distribution Substantial costs to store and dispose of hazardous utility. The Company had received approximately and non-hazardous materials have been incurred.

$ 29 million in gross revenues from a major industri- Significant additional costs could be incurred in the al customer in the local distribution utility's service future to meet the requirements of new laws and territory. The case resulted from a Supreme Court regulations and to clean up disposal sites under of Indiana decision which overruled an appeals existing legislation. Management has no knowl-court and voided an IURC order which assigned the edge of any material clean up costs related to the major industrial customer to the Company. Company's past disposal of hazardous and non-hazardous materials.

The Company is involved in a number of other legal proceedings and claims. While management Nuclear Plant is unable to predict the outcome of litigation, it is not expected that the resolution of these matters ISM owns and operates the two-unit 2,110 mw will have a material adverse effect on financial Cook Plant under licenses granted by a regulatory condition. authority. The operation of a nuclear facility involves special risks, potential liabilities, and Clean AI'r specific regulatory and safety requirements.

Should a nuclear incident occur at any nuclear The Clean Air Act Amendments of 1990 (CAAA) power plant facility in the United States, the require significant reductions in sulfur dioxide and resultant liability could be substantial. By agree-nitrogen oxide emissions from various AEP System ment ISM is partially liable together with all other generating plants. The first phase of reductions in electric utility companies that own nuclear generat-sulfur dioxide emissions (Phase I) began on January ing units for a nuclear power plant incident. Should 1, 1995 and the second, more restrictive phase nuclear losses or liabilities be underinsured or (Phase II) begins on January 1, 2000. The law also exceed accumulated funds, or should recovery established a permanent nationwide cap on sulfur through regulated rates be denied, results of opera-dioxide emissions after 1999. tions and financial condition would be negatively affected. Specific information about nuclear risk The AEP Systemwide compliance plan calls for management and potential liabilities is discussed fuel switching to medium-sulfur coal at the Compa- below.

ny's Tanners Creek Unit 4 with minimal capital cost. The Breed unit which is a Phase I affected Nuclear Incident Liability unit was closed in 1994. The Company's other generating units are not affected in Phase I ~ Public liability is limited by law to $ 8.9 billion should an incident occur at any licensed reactor in The Company will incur additional costs to the United States. Commercially available insur-comply with Phase II requirements at its generating ance provides $ 200 million of coverage. In the plants. In addition, a portion of the costs of com- event of a nuclear incident at any nuclear plant in pliance for the AEP System may be incurred the United States the remainder of the liability through the Power Pool (which is described in Note would be provided by a deferred premium assess-8). If the Company is unable to recover its compli- ment of $ 79.3 million on each licensed reactor ance costs from its customers, results of opera- payable in annual installments of $ 10 million. As tions would be adversely impacted. a result, IS.M could be assessed $ 158.6 million per nuclear incident payable in annual installments of 19

$ 20 million. The number of incidents for which making jurisdictions based on at least the lower end payments could be required is not limited. of the range in the most recent decommissioning study at the time of the last rate proceeding. The Nuclear insurance pools and other insurance Company records decommissioning costs in other policies provide $ 3.6 billion of property damage, operation expense and records a noncurrent de-decommissioning and decontamination coverage for commissioning liability equal to the decommission-Cook Plant. Additional insurance provides cover- ing cost recovered in rates which was $ 26 million age for extra costs resulting from a prolonged in 1994, $ 13 million in 1993 and $ 12 million in accidental Cook Plant outage. Some of the policies 1992. Decommissioning amounts recovered from have deferred premium provisions which could be customers are deposited in external trusts. Trust triggered by losses in excess of the insurer's fund earnings increase the fund assets and the resources. The losses could result from claims at recorded liability. Trust fund earnings decrease the the Cook Plant or certain other non-affiliated amount to be recovered from ratepayers. At nuclear units. The Company could be assessed up December 31, 1994 the Company has recognized to $ 41.9 million under these policies. a decommissioning liability of $ 212 million.

Spent Nuclear Fuel Disposal

5. BENEFIT PLANS:

Federal law provides for government responsibili-ty for permanent spent nuclear fuel disposal and The Company and its subsidiaries participate in assesses nuclear plant owners fees for spent fuel the AEP System pension plan, a trusteed, noncon-disposal. A fee of one mill per kilowatthour for fuel tributory defined benefit plan covering all employ-consumed after April 6, 1983 is being collected ees meeting eligibility requirements. Benefits are from customers and remitted to the U.S. Treasury. based on service years and compensation levels.

Fees and related interest of $ 154 million for fuel Pension costs are allocated by first charging each consumed prior to April 7, 1983 have been record- System company with its service cost and then ed as long-term debt with an offsetting regulatory allocating the remaining pension cost in proportion asset. The regulatory asset at December 31, 1994 to its share of the projected benefit obligation. The of $ 8.4 million is being amortized as rate recovery funding policy is to make annual trust fund contri-occurs. IS.M has not paid the government the pre- butions equal to the net periodic pension cost up to April 1983 fees due to various factors including the maximum amount deductible for federal income continued delays and uncertainties related to the taxes, but not less than the minimum contribution federal disposal program. At December 31, 1994, 'equired by the Employee Retirement Income funds collected from customers and related earn- Security Act of 1974.

ings including accrued interest totaled $ 145.6 million. Net pension costs for the years ended December 31, 1994, 1993 and 1992 were $ 5 million, $ 4.7 Decommissioning and Low Level Waste Accumula- million and $ 5.6 million, respectively.

tion Disposal An employee savings plan is offered which Decommissioning costs are accrued over the allows participants to contribute up to 17% of their service life of the Cook Plant. The licenses to salaries into three investment alternatives, including operate the two nuclear units expire in 2014 and AEP Co., Inc. common stock. An employer match-2017. After expiration of the licenses the plant is ing contribution, equaling one-half of the expected to be decommissioned through disman- employees'ontribution to the plan up to a maxi-tlement. Estimated decommissioning and low level mum of 3% of the employees'ase salary, is radioactive waste accumulation disposal costs invested in AEP Co., Inc. common stock. The range from $ 634 million to $ 988 million in 1993 employer's annual contributions totaled $ 3.9 million dollars. The wide range is caused by variables in in 1994, $ 3.5 million in 1993 and $ 3.3 million in assumptions including the estimated length of time 1992.

spent nuclear fuel must be stored at the plant subsequent to ceasing operations which depends Certain other benefits are provided for retired on future developments in the federal government's employees under an AEP System other postretire-spent nuclear fuel disposal program. Decommis- ment benefit plan. Substantially all employees are sioning costs are being recovered in the three rate- eligible for postretirement health care and life 20

I II ~ ~ NDIANA MICHIGANPOWER COIIIIPANY AND SUBSIDIARIES insurance if they have at least 10 service years and A Voluntary Employees Beneficiary Association are age 55 at retirement. Prior to 1993, net costs (VEBA) trust fund for OPEB benefits was estab-of these benefits were recognized as an expense lished and a corporate owned life insurance (COLI) when paid and totaled $ 2.7 million in 1992. program was implemented. The insurance policies have a substantial cash surrender value which is SFAS 106, Employers'ccounting for recorded, net of equally substantial policy loans, as Postretirement Benefits Other Than Pensions, was other property and investments. For the Indiana adopted in January 1993 for the Company's jurisdiction where OPEB costs are reflected in cost aggregate liability for postretirement benefits other of service, the amount contributed to the VEBA than pensions (OPEB) ~ SFAS 106 requires the trust fund is the difference between the pay-as-accrual during the employee's service years of the you-go OPEB cost and the SFAS 106 total OPEB present value liability for OPEB costs. Costs for the cost. This contribution is funded by amounts accumulated postretirement benefits earned and collected from ratepayers plus net earnings from not recognized at adoption are being recognized, in the COLI program. For FERC and Michigan jurisdic-accordance with SFAS 106, as a transition obliga- tions where recovery has not been approved and tion over 20 years. OPEB costs are determined by rates are insufficient to absorb these additional the application of AEP System actuarial assump- costs, the contribution to the VEBA trust fund is tions to each operating company's employee the cash generated by the COLI program. Contri-complement. The annual accrued OPEB costs for butions to the VEBA trust fund were $ 6.6 million in employees and retirees required by SFAS 106, 1994 and $ 1.3 million in 1993.

which includes the recognition of one-twentieth of the prior service transition obligation, were $ 13.2 million in 1994 and $ 12.4 million in 1993. 6. SUPPLEMENTARY INFORMATION:

The Company received approval from the IURC to Year Ended December 31 recover the increased OPEB costs resulting from 1994 1993 1992 SFAS 106. In the Michigan and wholesale juris- (in thousands) dictions, the Company received authority to defer Cash was paid for:

the increased OPEB costs which are not being Interest (net of currently recovered in rates. Future recovery of the capitalized amounts) $ 68,946 $ 82,509 $ 84,691 Income Taxes 85,854 68,303 15,285 deferrals and the annual ongoing increased OPEB costs will be sought in the next base rate filings. Honcash Acquisitions At December 31, 1994, $ 6.7 million of incremental Under Capital OPEB costs were deferred. Leases were 92,199 15,467 47,905 21

~ 4 ~

7. FEDERAL INCOME TAXES:

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

Year Ended December 31 1994 1993 1992 (in thousands)

Charged (Credited) to Operating Expenses (net):

Current $ 64,565 $ 93,974 $ 9,122 Deferred (15,331) (50,959) 25,405 Deferred Investment Tax Credits ~8)07955) ~8308) 34 707

~9028)

Total 41 25 ~ 99 Charged (Credited) to Nonoperating Income (net):

Current 1,390 6,026 1,569 Deferred (1,718) 1,054 4,492 Deferred Investment Tax Credits ~5722) ~235) ~645)

Total ~6060) 6 845 5 416 Total Federal Income Taxes as Reported ~35 029 ~4) 552 ~30 915 The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory tax rate, and the amount of federal income taxes reported, Year Ended December 31 1994 1993 1992 (in thousands)

Net Income $ 157,471 $ 129,313 $ 123,948 Federal Income Taxes 35 029 41 552 30 915 Pre-tax Book Income ~192 500 ~)70 865 ~)54 863 Federal Income Tax on Pre-tax Book Income at Statutory Rate (35% in 1994 and 1993; 34K in 1992) $ 67,375 $ 59,803 $ 52,653 Increase (Decrease) in Federal Income Tax Resulting From the Following Items:

Removal Costs (2,422) (2,632) (3,042)

Adoption of SFAS 109 5,271 Corporate Owned Life Insurance (4,521) (4,697) (4,402)

Nuclear Fuel Disposal Costs (4,498) (2,432) (2,068)

Investment Tax Credits (net) (13,875) (8,543) (9,011)

Other ~7030) ~52)8) ~3215)

Total Federal Income Taxes as Reported ~35 029 ~4) 552 ~30 915 Effective Federal Income Tax Rate 18.2X 24.3X 20.0X 22

~ le ~

DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES The following tables show the elements of the net ed for the out-of-pocket costs of energy delivered deferred tax liability and the significant temporary to the Power Pool and charged for energy received differences that gave rise to it: from the Power Pool.

December 31 Operating revenues include $ 140.5 million in 1994 1993 1994, $ 204.6 million in 1993 and $ 154.1 million (in thousands) in 1992 for energy and capacity supplied to the Deferred Tax Assets $ 235,165 $ 233,380 Power Pool. Purchased power expense includes Deferred Tax Llabllltlee ~798 810) ~787 300) charges of $ 33.1 million in 1994, $ 20.9 million in liat Deferred Tax Llabllltlea ~563 654) ~553 920) 1993 and $ 82.6 million in 1992 for energy re-Property Related ceived from the Power Pool.

Temporary Differences $ (498,124) $ (494,966)

Amounts Oue From Customers Power Pool members share in wholesale sales to For Future Federal unaffiliated utilities made by the Power Pool. The Income Taxes (109,806) (100,432)

Deferred Ket Gain- Company's share of the Power Pool wholesale Rockport Plant Unit 2 60,561 62,761 sales included in operating revenues were $ 54.1 All Other (net) ~)6 285) ~2) 283) million in 1994, $ 57 million in 1993 and $ 45.8 Total Ket Deferred million in 1992.

Tax Liabilities ~563 654) ~553 920)

The Company and its subsidiaries join in the filing In addition, the Power Pool purchases power of a consolidated federal income tax return with from unaffiliated companies for immediate resale to their affiliates in the AEP System. The allocation of other unaffiliated utilities. The Company's share of the AEP System's current consolidated federal these purchases was included in purchased power income tax to the System companies is in accor- expense and totaled $ 14.2 million in 1994, $ 5.1 dance with SEC rules under the 1935 Act. These million in 1993 and $ 6.5 million in 1992. Reve-rules permit the allocation of the benefit of current nues from these transactions are included in the tax losses to the System companies giving rise to above Power Pool wholesale operating revenues.

them in determining their current tax expense. The tax loss of the System parent company, AEP Coed The cost of power purchased from AEGCo, an Inc., is allocated to its subsidiaries with taxable affiliated company that is not a member of the income. With the exception of the loss of the Power Pool, was included in purchased power parent company, the method of allocation approxi- expense in the amounts of $ 82.4 million, $ 78.9 mates a separate return result for each company in million and $ 88 million in 1994, 1993 and 1992, the consolidated group. respectively.

The AEP System has settled with the Internal The Company operates the Rockport Plant and Revenue Service (IRS) all issues from the audits of bills AEGCo for its share of operating costs.

the consolidated federal income tax returns for the years prior to 1988. Returns for the years 1988 AEP System companies participate in a transmis-through 1990 are presently being audited by the sion equalization agreement. This agreement IRS. In the opinion of management, the final combines certain AEP System companies'nvest-settlement of open years will not have a material ments in transmission facilities and shares the effect on results of operations. costs of ownership in proportion to the System companies'espective peak demands. Pursuant to the terms of the agreement, equalization credits of 8: RELATED PARTY TRANSACTIONS: $ 50.3 million, 847A million and $ 48.2 million were recorded in other operation expense in 1994, 1993 Benefits and costs of the System's generating and 1992, respectively.

plants are shared by members of the Power Pool.

Under the terms of the System Interconnection Agreement, capacity charges and credits are designed to allocate the cost of the System's capacity among the Power Pool members based on their relative peak demands and generating re-serves. Power Pool members are also compensat-23

~ ~ 2 Revenues from providing barging services were million comprised of an unrealized holding gain of recorded in nonoperating income as follows: $ 21A million and an unrealized holding loss of

$ 1.0 million, with no effect on net income and/or Year Ended Oecember 31 shareholder's equity. The trust investments, report-1994 1993 1992 ed in other property and investments, had a fair (in thousands) value of 8321 million at January 1, 1994 and Affiliated Companies $ 24,001 $ 21,332 $ 20,154 consisted primarily of tax-exempt municipal bonds.

Unaffiliated Cnmpaniea 5 021 5 757 8 563 In accordance with SFAS 115, prior year amounts Total ~29 022 ~27 089 ~28 717 were not restated.

American Electric Power Service Corporation (AEPSC) provides certain managerial and profes- At December 31, 1994, the fair value of the sional services to AEP System companies. The trust investments was $ 353 million. Accumulated costs of the services are billed by AEPSC on a gross unrealized holding gains and losses were direct-charge basis to the extent practicable and on $ 5.5 million and $ 12.2 million, respectively, at reasonable bases of proration for indirect costs. December 31, 1994. The change in market value The charges for services are made at cost and during 1994 was a $ 27.1 million net holding loss.

include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Conf The trust investments'ost basis by security Inc. Billings from AEPSC are capitalized or type at December 31, 1994 was:

expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the (in thousands) regulation of the SEC under the 1935 Act. Treasury bonds $ 997 Tax-exempt bonds 332,098 Equity securities 1,665

9. FAIR VALUE OF FINANCIALINSTRUMENTS: Cash and cash equivalents 25 304 Total ~360 064 Nuclear Trust Funds Recorded at Market Value Proceeds from sales and maturities of securities were $ 20.1 million during 1994 which resulted in Effective January 1, 1994, the Company adopted $ 52,000 of realized gains and $ 155,000 of realized SFAS 115, Accounting for Certain Investments in losses. The cost of securities for determining Debt and Equity Securities, which requires fair realized gains and losses is original acquisition cost value accounting for investments in equity securi- including amortized premiums and discounts.

ties with readily determinable market values and investments in debt securities except those that the At December 31, 1994, the year of maturity of reporting enterprise has the positive intent and trust fund investments, other than equity securi-ability to hold to maturity. Debt securities not ties, was:

classified as held-to-maturity and qualifying equity securities, shall be classified as trading or avail- (in thousands) able-for-sale. The Company's investments held in 1995 $ 39,173 trust funds for decommissioning nuclear facilities 1996-1999 85,199 and for disposal of spent nuclear fuel have been 2000-2004 142,868 classified as available-for-sale. SFAS 116 requires After 2004 91 159 that unrealized gains and losses on investments Total ~358 399 classified as available-for-sale be reported as a Other Financial Instruments Recorded at Historical separate component of shareholder's equity. Cost However, due to the rate-making process, adjust-ments under SFAS 116 for unrealized gains and The carrying amounts of cash and cash equiva-losses to the carrying value of investments held in lents, accounts receivable, short-term debt, and the trusts result in corresponding adjustments to accounts payable approximate fair value because of regulatory assets and liabilities. the short-term maturity of these instruments. Fair values for preferred stocks subject to mandatory The cumulative effect of adopting SFAS 115 redemption were 8117 million and $ 99 million and resulted in an increase in the decommissioning and for long-term debt were $ 1.0 billion and $ 1.1 bil-spent nuclear fuel trust fund assets of $ 20.4 lion at December 31, 1994 and 1993, respectively.

24

sl ~ ~

NDIAIVAMICHIGANPOWER COMPANY AND SUBSIDIARIES 3

The carrying amounts for preferred stock subject to Properties under operating leases and related mandatory redemption were $ 135 million and $ 100 obligations are not included in the Consolidated million and for long-term debt were $ 1.1 billion and Balance Sheets.

$ 1.1 billion at December 31, 1994 and 1993, respectively. Fair values are based on quoted Lease rentals are primarily charged to operating market prices for the same or similar issues and the expenses in accordance with rate-making treat-current dividend or interest rates offered for instru- ment. The components of rental costs are as ments of the same remaining maturities. The follows:

carrying amount of the pre-April 1983 spent nucle-ar fuel disposal liability approximates the Year Ended Oecember 31 1994 1993 1992 Company's best estimate of its fair value. (in thousands)

Operating Leases $ 104,519 $ 103,884 $ 109,466

10. LEASES: Amortization of Capital Leases 30,875 46,063 24,124 Interest on Leases of property, plant and equipment are for Capital Leases 7 643 8 073 7 473 periods up to 35 years and require payments of Total Rental related property taxes, maintenance and operating Costs ~143 037 ~158 020 ~l41 063 costs. The majority of the leases have purchase or Future minimum lease payments consisted of renewal options and will be renewed or replaced by the following at December 31, 1994:

other leases.

Non-Cancelable Properties under capital leases and related obliga- Capital Operating Leases Leases tions recorded on the Consolidated Balance Sheets (in thousands) are as follows:

Oecember 31 1995 $ 11,558 $ 97,725 1994 1993 1996 10,370 97,579 (in thousands) 1997 9,262 95,772 1998 8,299 90,631 Electric Utility Plant: 1999 7,171 90,489 Production $ 8,371 $ 8,033 Later Years 40 570 1 919 552 Distribution 14,717 14,717 General: Total Future Hinimum Nuclear Fuel Lease Payments 07,230(a) ~2 391 748 (net of amortization) 89,478 45,661 Other 53 701 40 418 Less Estimated Total Electric Utility interest Element 24 119 Plant 166,347 116,829 Accumulated Amortization 27 225 27 359 Estimated Present Net Electric Utility Value of Future Plant 139 122 09 470 Hinimum Lease Payments 63,111 Other Property 15,842 11,269 Unamortized Nuclear Accumulated Amortization 2 375 1 906 Fuel 09 470 Net Other Property 13 467 9 203 Total ~152 509 Net Properties under Capital Lease 152 589 98 753 (a) Hinimum lease rentals do not include nuclear fuel rentals. The rentals are paid in proportion to heat Capital Lease Obligations: produced and carrying charges on the unamortized Noncurrent Liability $ 113,586 $ 78,168 nuclear fuel balance. There are no minimum lease Liability Oue Within payment requirements for leased nuclear fuel.

One Year 39 003 20 505 Total Capital Lease Obligations ~152 509 ~90 753 25

0 ~

iO 3

~

11. CUMULATIVEPREFERRED STOCK:

At December 31, 1994, authorized shares of cumulative preferred stock were as follows:

Par Value Shares Authorized

$ 100 2,250,000 25 11,200,000 The cumulative preferred stock is callable at the price indicated plus accrued dividends. The involuntary liquidation preference is par value. Unissued shares of the cumulative preferred stock may or may not possess mandatory redemption characteristics upon issuance. During 1993 the Company redeemed and cancelled the following entire series: 8.68% series consisting of 300,000 shares and $ 2.15 and $ 2.25 series each consisting of 1,600,000 shares.

A. Cumulative Preferred Stock Not Subject to Mandatory Redemption:

Cell Price Shares Amount Oecenber 31, Par Number of Shares Redeened Outstanding December 31 Series 1994 Value Year Ended Oecember 31 Oecember 31 1994 1994 1993 1994 1993 1992 (in thousands) 4"1/8X $ 106.125 $ 100 120,000 $ 12,000 $ 12,000 4.56K 102 100 60,000 6,000 6,000 4.12K 102.728 100 40,000 4,000 4,000 7.08K 101.85 100 300,000 30,000 30,000 7.76K 350,000 35 ODD 52 000 ~07 ODO 3

B. Cumulative Preferred Stock Subject to Mandatory Redemption:

Shares Amount Par Outstanding December 31 Series(a) Value Oecember 31 1994 1994 1993 (in thousands) 5.90K (b) $ 100 400,000 $ 40,000 $ 40,000 6-1/4X(c) 100 300,000 30,000 30,000 6.30K (d) 100 350,000 35,000 6-7/8X(e) 100 300,000 30 000 30 000

~335 000 ~300 ODD (a) Not callable until after 2002. There aro no aggregate sinking fund provisions through 2002.

(b) Shares issued November 1993. Commencing in 2004 and continuing through the year 2008, a sinking fund will require tho redemption of 20,000 shares each year and the redemption of tho remaining shares outstanding on January 1, 2009, in each case at $ 100 per share.

(c) Sharos issuod November 1993. Commencing ln 2004 end continuing through tho year 2008, a sinking fund will require tho redemption of 15,000 shares each year and the redemption of tho remaining shares outstanding on April 1, 2009, in each case at $ 100 per share.

(d) Shares issued February 1994. Commencing in 2004 and continuing through the year 2008, a sinking fund will require the redemption of 17,500 shares each year and the redemption of tho remaining shares outstanding on July 1, 2009, in each case at $ 100 por share.

(e) Shares issued February 1993. Commencing in 2003 and continuing through tho year 2007, a sinking fund will require the redemption of 15,000 shares each year and tho redemption of tho remaining shares outstanding on April 1, 2008, in each case at $ 100 por share.

26

t )S ~

DIANA MICHIGANPOWER COMPANY AND S(IBSIDIARIES

12. LONG-TERM DEBT AND LlNES OF CREDlT: Installment purchase contracts have been entered into in connection with the issuance of pollution Long-term debt by major category was out- control revenue bonds by governmental authorities standing as follows: as follows:

December 31 December 31 1994 1993 1994 1993 (ln thousands) (in thousands)

First Mortgage Bonds $ 561,770 $ 571,468 ~Rate Due Installment Purchase City of Lawronceburg, Indiana:

Contracts 308,087 307,823 7 2015- April 1 $ 25,000 $ 25,000 Other Long-term Debt (o) 153,977 147,810 5.9 2019 - Novembor 1 52,000 52,000 Notes Payablo to Banks 40,000 40,000 City of Rockpcrt, Indiana:

Sinking Fund Debentures 6 053 6 053 9-1/4 2014- August 1 50,000 50,000 1,069,887 1,073,154 6-3/4(a) 2014 - August 1 50,000 50,000 Less Portion Due Within (b) 2014- August 1 50,000 50,000 Ono Year 140 000 7.6 2016 - March 1 40,000 40,000 City of Sullivan, Indiana:

Total ~929 007 ~)073 154 5.95 2009 - May 1 45,000 45,000 (a) Nuclear Fuel Disposal Costs including interest accrued.

unamortized Discount ~3913) ~4) 77) 308,087 307,823 Seo Note 4.

Less Portion Due Within One Year 100 000 First mortgage bonds outstanding were as fol-lows: Total ~208 007 ~307 023 December 31 1994 1993 (a) Tho adjustable interest rate will chango on August 1, (ln thousands) 1995.

(b) Tho variable interest rate is determined weekly. The Rate Due average weighted interest was 3.8% for 1994 and 3.0% for 7 1998- May 1 $ 35,000 $ 35,000 1993.

7.30 1999- December 15 35,000 35,000 7.63 2001 - J Uno 1 40,000 Under the terms of certain installment purchase 7.60 2002- N ovember 1 50,000 50,000 contracts, the Company is required to pay amounts 7.70 2002- December 15 40,000 40,000 sufficient to enable the cities to pay interest on and 6.80 2003- J uly 1 20,000 20,000 the principal (at stated maturities and upon 6.55 2003- October 1 20,000 20,000 mandatory redemption) of related pollution control 6.10 2003- November 1 30,000 30,000 revenue bonds issued to finance the construction 6.55 2004- March 1 25,000 of pollution control facilities at certain generating 8-3/4 2017- F ebruary 1 100,000 plants. On certain series the principal is payable at 9.50 2021 - May I 10,000 10,000 stated maturities or on the demand of the bond-9.50 2021 - May 1 10,000 10,000 9.50 2021 - May 1 20,000 20,000 holders at periodic interest adjustment dates.

8.75 2022- May 1 50,000 50,000 Certain series are supported by bank letters of 8.50 2022- D ecember 15 75,000 75,000 credit which expire in 1995. As a result these 7.80 2023- J uly 1 20,000 20,000 series are classified as due within one year on the 7.35 2023- 0 ctobor 1 20,000 20,000 December 31, 1994 Consolidated Balance Sheet.

7.20 2024- F obruary 1 40,000 40,000 7.50 2024- March 1 25,000 A $ 40 million unsecured promissory note payable Unamcrti zed Disc ount (net) ~3230) ~3532) to a bank is due November 19, 1995 at an annual interest rate of 9.07%.

Total 561 770 571 468 The sinking fund debentures are due May 1, Certain indentures relating to the first mortgage 1998 at an interest rate of 7-1/4%. Prior to bonds contain improvement, maintenance and re- December 31, 1994, sufficient principal amounts of placement provisions requiring the deposit of cash debentures had been reacquired in anticipation of or bonds with the trustee, or in lieu thereof, certifi- all future sinking fund requirements. Additional cation of unfunded property additions. debentures of up to $ 300,000 may be called annually.

27

At December 31, 1994, annual long-term debt In 1994 paid-in capital was charged $ 422,000 payments, excluding premium or discount, are as for costs associated with issuing and redeeming follows: cumulative preferred stock. In 1993 IS.M's parent Princi al Amount made a cash capital contribution of $ 10 million and (in thousands) a charge of $ 1.2 million for the issuance of three 1995 $ 140,000 series of cumulative preferred stock was recorded 1996 to paid-in capital. There were no other transactions 1997 affecting the common stock or paid-in capital 1998 41,053 accounts in 1994, 1993 and 1992.

1999 35,000 Later Years 060 933 Total ~3033 030

14. UNAUDITED QUARTERLY FINANCIALINFOR-Short-term debt borrowings are limited by provi- IVIATION:

sions of the 1935 Act to $ 200 million and further limited by charter provisions to $ 130 million. Lines Ouarterly Periods Operating Operating Net of credit are shared with AEP System companies Ended Revenues Income Income and at December 31, 1994 and 1993 were avail- (in thousands) able in the amounts of $ 558 million and $ 537 mil- 1994 Harch 31 $ 337,921 $ 58,815 $ 44,968 lion, respectively. Commitment fees of June 30 310,104 54,632 - 37,274 approximately 3/16 of 1% of the unused short- September 30 317,061 55,409 37,728 term lines of credit are paid each year to the banks December 31 286,223 52,875 37,501 to maintain the lines of credit. Outstanding short- 1993 term debt consisted of commercial paper as fol- Harch 31 302,968 53,269 28,522 lows: June 30 278,100 40,722 21,397 September 30 320,409 52,898 33,658 Balance Oecember 31 301,166 63,031 45,736 Weighted Outstanding Average in thousands Interest Rate December 31, 1994 $ 50,600 6.3X Oecember 31, 1993 50,075 3.6

13. COMMON SHAREOWNER'S EQUITY:

Mortgage indentures, debentures, charter provi-sions and orders of regulatory authorities place various restrictions on the use of retained earnings for the payment of cash dividends on common stock. At December 31, 1994, $ 5.9 million of retained earnings were restricted. Regulatory approval is required to pay dividends out of paid-in capital.

28

~ d ~ DIANA MICHIGANPOWER COMPANY AND SUBSIDIARIES OPERATING STATISTICS 1994 1993 1992 1991 1990 OPERATING REVENUES (in thousands):

Retail:

Residential:

Without Electric Heating $ 227,358 $ 205,315 $ 209,682 $ 206,257 $ 192,822 With Electric Heating 107 523 97 560 90 553 93 209 00 710 Total Residential 334,881 302,883 308,235 299,546 281,540 Comercial 247,938 220,938 228,285 216,303 205,025 Industrial 291,527 250,939 267,643 241,858 244,773 Miscellaneous 6 316 5 593 11 012 12 120 11 799 Total Retail 880,662 780,353 815,175 769,827 743,137 Wholesale (sales for resale) 352 089 404 910 369 379 436 003 510 080 Total Revenues from Energy Sales 1,233,551 1,185,263 1,184,554 1,205,910 1,261,217 Provision for Refunds of Revenues Collected in Prior Years Total Het of Provision for Refunds

~755) ~4038) 5 176 ~5176) 1,233,551 1,184,508 1,180,516 1,211,086 1,256,041 Other 17 750 10 135 16 239 14 701 15 473 Total Operating Revenues 1 251 309 1 202 643 1 196 755 1 225 867 1 271 514 SOURCES ANO SALES OF ENERGY (in millions of kilowatt-hours):

Sources:

Net Generated:

Fossil Fuel 13,022 12,236 11,597 12,109 14,451 Nuclear Fuel 9,291 16,313 6,418 15,524 11,115 Hydroelectric 95 106 100 109 127 Total Het Generated 22,408 28,655 18,115 27,742 25,693 Purchased and Power Pool ~5757 ~4879 ~9342 ~5237 ~7983 Total Sources 28,165 33,534 27,457 32,979 33,676 Less: Losses, Company Use, Etc. ~1398 ~1349 ~1466 ~1454 ~1633 Net Sources ~26 767 ~32 185 ~25 991 ~31 525 ~32 043 Sales:

Retail:

Residential:

Without Electric Heating 3,210 3,178 3,001 3,166 2,955

'With Electric Heating ~1727 ~1706 ~1633 ~1625 ~1525 Total Residential 4,937 4,884 4,634 4,791 4,480 Com)ercial 4,148 3,977 3,747 3,726 3,536 Industrial 6,453 6,025 5,685 5,382 5,452 Miscellaneous 82 83 194 233 229 Total Retail 15,620 14,969 14,260 14,132 13,697 Wholesale (sales for resale) ~11 147 ~17 216 ~II 731 ~17 393 ~18 346 Total Sales ~26 767 ~32 185 ~25 991 ~31 525 ~32 043 29

5 ~ C8 OPERATING STATISTICS (Concluded) 1994 1993 1992 1991 990 AVERAGE COST OF FUEL CONSUNEO (in cents):

Per Nillion Btu:

Coal 124 130 136 141 145 Nuclear 42 36 54 48 58 Overall 85 72 103 84 105 Per Kilowatt-hour Generated:

Coal 1.21 1.27 1.34 1.39 1.42 Nuclear .47 .40 .61 .53 .64 Overall .90 .77 1.08 .91 1.08 RESIOENTIAL SERVICE - AVERAGES:

Annual Kwh Use per Customer:

With Electric Heating 17,907 17,980 17,513 17,702 16,897 Total 10,572 10,559 10,107 10,535 9,944 Annual Electric Bill:

'With Electric Heating $ 1,115.19 $ 1,028.26 $ 1,056.91 $ 1,016.16 $ 983.28 Total $ 717.17 $ 654.76 $ 672.31 $ 658.76 $ 624.95 Price per Kwh (in cents):

With Electric Heating 6.23 5.72 6. 04 5.74 5.82 Total 6.78 6.20 6.65 6.25 6.28 NUNBER OF CUSTONERS:

Year-End:

Retail:

Residential:

Without Electric Heating 372,473 369,385 366,835 364,154 362,645 With Electric Heating ~97 40 95 795 94 175 92 657 91 179 Total Residential 469,875 465,180 461,010 456,811 453,824 Camercial 53,927 53,081 52,542 51,491 50,994 Industrial 5,213 5,157 5,000 4,847 4,801 Hiscellaneous 1 DD6 1 783 1 751 2 226 2 16D Total Retail 53D,821 525,201 520,303 515.375 511,779 Wholesale (sales for resale) 54 56 53 53 55 Total Customers ~530 875 525 257 ~520 356 515 428 ~577 834 30

DIVIDENDS AND PRIG RANGES OF CUMULATIVE EFERRED STOCK By Quarters (1994 and 1993) 1994 - uarters 1993 - uarters 1st 2nd 3rd 4th 1st 2nd 3rd 4th CUMULATIVE PREFERRED STOCK

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

Ask - High

- Low Bid - High 55-5/8 54-1/8 50"5/8 46-1/8

- Low 49 45-1/2 45-1/2 45-1/2 4.12K Ser ies Dividends Paid Per Share $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 $ 1.03 Market Price - $ Per Share (OTC)

Ask - High

- Low Bid - High 58-1/2 54 . 48 48 51 51-1/2 55"1/4 58-1/2

- Low 51 46-1/2 46-1/8 43-1/2 48 48 51 54-3/4 5.90li Series (a)

Dividends Paid Per Share $ 1.475 $ 1.475 $ 1.475 $ 1.475 $ 0.9342 Market Price - $ Per Share (OTC)

Ask (high/low)

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

Dividends Paid Per Share $ 1.5625 $ 1.5625 $ 1.5625 $ 1.5625 $ 0.5382 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 6.30K Series (b)

Dividends Paid Per Share $ 0.9275 $ 1.575 $ 1.575 $ 1.575 Market Price - $ Per Share (OTC)

Ask (high/low)

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

Dividends Paid Per Share $ 1.71875 $ 1.71875 $ 1.71875 $ 1.71875 $ 0.84 $ 1.71875 $ 1.71875 $ 1.71875 Market Price - $ Per Share (OTC)

Ask (high/low)

Bid (high/low) 7.08K Series Dividends Paid Per Share $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 $ 1.77 Market Price - $ Per Share (MYSE) - High 97-1/2 95 87-1/2 80 92 96 99-5/8 100-1/8

- Low 94 83 80 76 89-1/4 91 96-3/8 95 31

DIVIDENDS AND PRIG RANGES OF CUMULATIVEP EFERRED STOCK ~

By Quarters (1994 and 1993) (Concluded) 1994 - uarters 1993 - uar ters 1st 2nd 3rd 4th 1st 2nd 3rd 4th CUMULATIVE PREFERREO STOCK 7.76K Series (Redeemed)

Dividends Paid Per Share $ 0.9054 $ 1.94 $ 1.94 $ 1.94 $ 1.94 Market Price - $ Per Share (NYSE) - High 101 102-1/4 102 104 102-3/4

- Low 100 95-3/4 98 100 98-1/2

($ 100 Par Value) 8.68K Series (Redeemed)

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

- Low 100 101 101 101-1/4

($ 25 Par Value)

$ 2. 15 Series (Redeemed)

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

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

$ 2.25 Series (Redeemed)

Oividends Paid Per Share $ 0.375 Market Price - $ Per Share (MYSE) - High 26-3/4

- Low 25-1/2 CSE - Chicago Stock Exchange OTC - Over -the-Counter NYSE - New York Stock Exchange Note - The above bid and asked quotations represent prices between dealers and do not represent actual transactions.

Market quotations provided by National Ouotation Bureau, Inc.

Dash indicated quotation not available.

(a) Issued November 1993 (b) Issued February 1994 (c) Issued February 1993 32

DIANA MICHIGANPOWER COMPANY u

SECURITY OWNER INQUIRIES Security owners should direct their inquiries to the Security Owner Relations Division using the toll free number: 1-800-AEP-COMP (1-800-237-2667) or by writing to:

Bette Jo Rozsa Security Owner Relations Division American Electric Power Service Corporation 28th Floor 1 Riverside Plaza Columbus, OH 43215-2373 FORM 10-K ANNUALREPORT The Annual Report (Form 10-K) to the Securities and Exchange Commission will be available in April 1995 at no cost to shareowners. Please address such requests to:

Geoffrey C. Dean American Electric Power Service Corporation 27th Floor 1 Riverside Plaza Columbus, OH 43215-2373 TRANSFER AGENT AND REGISTRAR OF CUMULATIVEPREFERRED STOCK First Chicago Trust Company of New York P.O. Box 2534 Suite 4692 Jersey City, NJ 07303-2534 33

Indiana Michigan Power Service Area and the American Electric Power System LAKE MICHIGAN MICHIGAN IAKE ERIE OHIO INDIANA WEST VIRGINIA VI RG IN IA KENTUCKY Indiana Michigan Power Co. area

~ Other AEP operating companies'reas TENNESSEE Q Major power plant O~

C3+ printed on recycled paper

ATTACHMENT 2 TO AEP:NRC'0909K INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1995

0 - ~ () '

p

Indiana Michigan Power Co.

1995 Forecasted Sources and Uses of Funds Based on Forecasted Case 9501

$ Millions Projected 1995 Net Income After Taxes 136.4 Less Divklends Paid 122.5 Retained Earnings 13.9 Adjustments:

Depreciation And Amortization 163.0 Deferred Operating Costs 2.9 Deferred Federal Income Taxes and Investment Tax Credits (26.4)

AFUDC (3.1)

Other 7.7 Total Adjustments 144.1 Internal Cash Flow 158.0 Average Quarterly Cash Flow 39.5 Average Cash Balances and Short-Term Investments 8.9 Total

0 0 ~l S