ML17333A426

Indiana Michigan Power Co 1995 Annual Rept. W/960412 Ltr

ML17333A426
Person / Time
Site:	Cook
Issue date:	12/31/1995
From:	FITZPATRICK E INDIANA MICHIGAN POWER CO. (FORMERLY INDIANA & MICHIG
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
AEP:NRC:0909L, AEP:NRC:909L, NUDOCS 9604160188
Download: ML17333A426 (40)

Text

CATEGORY 1 REGULAR...Z INFORMATION DISTRIBUTION YSTEM (RIDS)-ACCESSION NBR:9604160188 DOC.DATE: 95/12/31 NOTARIZED:

NO FAC.L":p0-, 315 Donald C.Cook Nuclear Power Plant, Unit 1, Indiana M 50-3.';.6 Donald C.Cook Nuclear Power Plant, Unit 2, Indiana M AUTH.NAME AUTHOR AFFILIATION FITZPATRICK,E.

Indiana Michigan'Power Co.(formerly Indiana a Michigan Ele RECIP.NAME RECIPIENT AFFILIATION

SUBJECT:

"Indiana Michigan Power, DISTRIBUTION CODE: M004D COPIES TITLE: 50.71(b)Annual Financial NOTES: Co 1995 Annual Rept." W/960412 ltr.C RECEIVED:LTR (ENCL l SIZE:~5 A Report T RECIPIENT ID CODE/NAME PD3-1 LA HICKMAN J INTERNAL: "'ILE CENTER 01 EXTERNAL: NRC PDR COPIES LTTR ENCL 1 1 1 1 1 1 1 1 RECIPIENT ID CODE/NAME PD3-1 PD COPIES LTTR ENCL 1 1 D 0 NOTE TO ALL"RZDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTEl CONTACT THE DOCUMENT CONTROL DESK, ROOM OWFN 5D-5(EX'15-2083)

TO ELIMZNATE YOUR NAME FROM DISTRIBUTION LISTS FOR DOCUMENTS YOU DON'T NEEDI TOTAL NUMBER OF COPIES RF(>U RED: LTTR 5 ENCL 5 q4', a indiana Michigan~Power Company P.O.Box 16631 Columbus, OH 43216 April 12, 1996 AEP:NRC:0909L 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 annual report for 1995.Attachment 2 contains a copy of I&M's projected cash flow for 1996.These reports are submitted pursuant to 10 CFR 50.71(b)and 10 CFR 140.21(e).

Sincerely, E.E.Fitzpatrick Vice President eh Attachments CC: A.A.Blind G.Charnoff H.J.Miller NFEM Section Chief NRC Resident Inspector-Bridgman J.R.Padgett 9604i60i88 95i23i PDR ADQCK 050003i5 I PDR yr~(}OQQ pg$

ATTACHMENT 1 TO AEP'NRC:0909L INDIANA MICHIGAN POWER COMPANY'S ANNUAL REPORT FOR 1995 In iana Michigan Power Company 1 995 Annual Report

(((~NA MICHIGAN POWER COI(IIPANY AND SUBSIDIARIES One Summit Square, P.O.Box 60, Fort Wayne, indiana 46801 CONTENTS Background

.Directors and Officers~2~~3 Selected Consolidated Financial Data..Management's Discussion and Analysis of Results of Operations and Financial Condition..5-9 Independent Auditors'eport

.10 Consolidated Statements of Income Consolidated Balance Sheets 12-13 Consolidated Statements of Cash Flows Consolidated Statements of Retained Earnings Notes to Consolidated Financial Statements

..Operating Statistics

.14.15 1 6-28 29-30 Dividends and Price Ranges of Cumulative'Preferred Stock 31-32 BACKGROUND INDIANA MICHIGAN POWER COMPANY (the Company)is engaged in the generation, purchase, transmission and distribution of electric power.The Company serves approximately 537,000 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, electrical and electronic machinery, transportation equipment, fabricated metal products, rubber and miscellaneous plastic products and chemicals and allied products.The Company is a subsidiary of American Electric Power Company, Inc., a public utility holding company, and was organized under the laws of Indiana on February 21, 1925.As of January 1, 1996, the Company began doing business as American Electric Power (AEP)along with all of the parent's operating subsidiary companies in order to serve its customers more efficiently as one operating organization realigned by distinct, separately managed generation, energy delivery and non-regulated business groups.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 owned by the Company and affiliated companies.

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 2,110 mw of nuclear generation.

The Company owns the two unit Donald C.Cook Nuclear Plant located in Michigan.The generating plants and transmission facilities of the Company and certain other affiliated AEP System utility subsidiaries are operated as an integrated system with their costs and benefits shared through the AEP System Power Pool and AEP Transmission 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 that are not members of the Power Pool, and with numerous unaffiliated utilities.

IND MICHIGAN POWER COMPANY AND SUBSIDIARIES Dl (ACTORS Mark A.Bailey (a)Coulter R.Boyle, III (b)Gregory A.Clark (c)Peter J.DeMaria William N.D'Onofrio OFFICERS E.Linn Draper, Jr.William J.Lhota Gerald P.Maloney James J.Markowsky Richard C.Menge (a)Albert H.Potter David B.Synowiec (c)Dale M.Trenary (b)Joseph H.Vipperman (b)William E.Walters (b)E.Linn Draper Jr.Chairman of the Board and Chief Executive Officer William J.Lhota (b)President and Chief Operating Officer Richard C.Menge (a)President and Chief Operating Officer Mark A.Bailey (a)Vice President John F.DiLorenzo, Jr.Secretary Armando A.Pena (d)Treasurer Elio Bafile Assistant Controller and Assistant Secretary Leonard V.Assante Assistant Controller A.Alan Blind Site Vice President, Donald C.Cook Nuclear Plant Coulter R.Boyle, III (b)Vice President Peter J.DeMaria Vice President and Controller William N.O'Onofrio (a)Vice President Eugene E.Fitzpatrick Vice President Gerald P.Maloney Vice President James J.Markowsky Vice President William L.Scott (d)Assistant Controller John M.Adams, Jr.(d)Assistant Secretary Jeffrey D.Cross (e)Assistant Secretary Robert G.Griffin (f)Assistant Secretary Carl J.Moos (g)Assistant Secretary John B.Shinnock Assistant Secretary Bruce M.Barber Assistant Treasurer Joseph H.Vipperman (b)Vice President Christopher J.Keklak (d)Assistant Treasurer Gerald R.Knorr (e)Assistant Treasurer As of January 1, 1996 the cunent directors and officers of Indiona Michigan Power Company wore omployoes of American Electric Power Service Corporation with seven exceptionst Messrs.Bofile, Blind, Boyle, Clark, Griffin, Trenary and Walters, who were omployees of Indiana Michigan Power Company.tof Resigned Jonoetr 1, 1996 tbf Elected Jenoottr 1, 1996 Icf Elected Aftn7 25, 1995 Idf Elected November 1, 1995 lof Resigned November 1, 1995 ill Elected Septetnber 1, 1995 (gl Resigned September 1, 1995 Selected Consolidated Financial Data INCOME STATEMENTS DATA: 1994 rEn Dcm~1 (in thousands) 19 2 Operating Revenues Operating Expenses Operating Income Nonoperating Income (Loss)Income Before Interest Charges Interest Charges Net Income Preferred Stock Dividend Requirements Earnings Applicable to Common Stock S1,283,157 1 077 434 S1,251,309

~12~4 S1,202,643

~924 5 S1,196,755

~100 997 S1,225,867

~998 9 205,723~272 221,969~742 210,158 195,788 227,528~24)~11~721 211,995 229,397~70 03~71 89 209,924 209,903~85 2 223,807~)44 129 301~145 821 4 115 088 4 108 531 4 121 515 141,092 157,502 129,344 123,983 136,963~1791~11 1~14 2~15 4 2~144 BALANCE SHEETS DATA: 1995 19 4 Dec mb r 31~199 (in thousands)

~19 2 19 1 Electric Utility Plant Accumulated Depreciation and Amortization Net Electric Utility Plant S4,319,564 S4,269,306 S4,290,957 S4,266,480 S4,135,820 1 7~14~5~15~94(2~1714 2 1 fg~14~12~14 42 567 599 42 609 366 42 576 128 42 635 042~26'l4 471 Total Assets~3928 337~3878 035 43 723 648 43 608 645~3442 606 Common Stock and Paid-in Capital Retained Earnings Total Common Shareholder's Equity 951 026 41 022 793$1 006 892 4 968 263 4 953 127 S 787,686 S 790,234 S 790,625 S 781,818 S 781,783~235 1 7~216 65~177 8~171 09~124 Cumulative Preferred Stock: Not Subject to Mandatory Redemption Subject to Mandatory Redemption (a)Total Cumulative Preferred Stock S 52,000 135 000 S 197,000 S 197,000 S 87,000 100 000 S 52,000 135 000 197 000 4 187 000 4 187 000 4 187 000 4 197 000 Long-term Debt (a)$1 040 101 41 069 887 41 073 154~1211 623~1130 709 Obligations Under Capital Leases (a)ll 142 506 4 152 589 4 98 753 4 126 689 102 985 Total Capitalization and Liabilities (al Including gordon due wirhrn one year.43 928 337 43 878 035 43 723 648 43 608 645~3442 606 DIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES MANAGElVlENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION Business Outlook Since its enactment in 1992, the Energy Policy Act has fostered competition in the generation and sale of electricity in the wholesale market.The prospect for market driven rates is powering a movement, mainly among large industrial energy users, to introduce competition to the retail market as well.As a result management expects that competition will be a significant factor influencing the Company's future results of operations.

Among the other factors that could impact future earnings are nuclear fuel disposal costs and nuclear decom-missioning costs.A significant expansion of competition in the generation and sale of electricity could result in an adverse effect on future results of operations from stranded costs and the write-off of regulatory assets.Stranded costs occur when a customer switches to a new supplier creating the issue of who pays for investments and commitments that are no longer needed, economical or recoverable in a competitive market.The amount of any losses the Company may experience from stranded costs depends on the extent to which direct competition is introduced to the Company's business and the market price of energy.Cost-based regulation traditionally results in the recognition of revenues and expenses in accordance with rate commission orders which can result in revenue and expense recognition in different time periods than for enter-prises that are not regulated.

As a result, regula-tory assets have been recorded by regulated utility companies representing the deferral of costs for recovery in future periods.At December 31, 1995, the Company had$459 million of regulatory assets.In order to maintain regulatory assets, the Com-pany's rates must be cost-based regulated.

Man-agement has reviewed the evidence currently available and concluded that the Company contin-ues to meet the requirements to apply rate-regu-lated accounting standards.

In the event a portion of the Company's business no longer met these requirements, regulatory assets would have to be written off for that portion of the business.Whether future results of operations are adversely affected by losses or write-offs will also depend on whether and how equitable recovery is provided for by the applicable regulators.

We intend to seek appropriate recovery of any stranded costs and regulatory assets that may result from a transition to competition.

The Company, as a member of the AEP System, has the financial strength, geographic reach, loca-tion and cost structure to be an able competitor.

Although no assurance can be given that the Company can maintain this position in the future, management is taking steps to prepare for the challenges that increased competition will present.In 1995 management took steps to prepare for competition by realigning the Company's opera-tions, along with the operations of the AEP Sys-tem's other operating companies,,into functional operating units, expanding marketing and customer service efforts and proposing a plan for an orderly transition to retail competition.

Management also proposed and filed open access transmission rates.The realignment from separate operating company organizations to distinct fossil-fired and hydroelec-tric generation, nuclear generation and energy delivery operating units will facilitate the unbundling of electric services to separate competitive genera-tion services from regulated transmission and distribution services.It also should facilitate our ability to more efficiently and effectively meet customer needs.Process improvement and cost control will be key performance objectives for our new operating units.In October of 1995 management proposed the creation of an Independent System Operator to operate a multi-state transmission grid to facilitate equal, safe and efficient transmission.

Management also proposed the eventual creation of a Regional Power Exchange that would accept offers to buy and sell power and would settle transactions based on the price at which supply and demand are balanced.Under the proposal regulators would continue to regulate delivery services and provide for the recovery of any stranded costs and regula-tory assets through a usage charge.

Management has also offered access to AEP's extensive transmission grid at 142 interconnections to all parties under the same terms and conditions available to the AEP System.This should provide the Company with greater opportunities for trans-mission service revenues.Management has also responded to our retail customers'eeds by intro-ducing new cost-based regulated rate designs (interruptible buy-through and real time pricing).These proposals were issued to enable the Com-pany to participate in a meaningful way in the process of shaping the form of the future competi-tive playing field.Our success will depend on our ability to obtain a level playing field, improve and expand on our energy sales and services and maintain and improve on our relatively low cost structure.

Nuclear Cost The Company's nuclear plant, the Donald C.Cook Nuclear Plant, has recently achieved a superior rating from the Institute of Nuclear Power Opera-tions, a nuclear industry oversight group, and received improved Nuclear Regulatory Commission (NRC)performance ratings.In an effort to continue to reduce costs and enhance organizational effi-ciency, management announced in November that during the summer of 1996 we will consolidate our Columbus-based nuclear engineering, management and support staff with the plant staff at or near the Cook Plant in Bridgman, Michigan.The cost to operate and maintain the two-unit Cook Plant is impacted by federal laws and NRC requirements.

The Nuclear Waste Policy Act of 1982 established federal responsibility for the permanent off-site disposal of spent nuclear fuel and high-level radioactive waste.By law the Company participates in the Department of En-ergy's (DOE's)Spent Nuclear Fuel (SNF)disposal program which is described in Note 3 of the Notes to Consolidated Financial Statements.

Since 1983 our consumers of nuclear generated electricity have paid$237 million for the future disposal, at a yet to be built DOE disposal facility, of spent nuclear fuel consumed at the Cook Plant.Under the provisions of the Nuclear Waste Policy Act, collections from customers are to provide the DOE with money to build a permanent repository for spent fuel.The federal government has not made sufficient prog-ress toward the selection of a site and construction of a permanent repository and as long as there is a delay in establishing the permanent storage reposi-tory for spent nuclear fuel, the cost of a temporary or permanent repository will continue to increase.The cost to decommission the Cook Plant is affected by NRC regulations and the DOE's SNF disposal program.Studies completed in 1994 estimate the cost to decommission the plant and dispose of low-level nuclear waste accumulation to range from$634 million to$988 million in 1993 dollars.The decommissioning estimate could escalate due to uncertainty in the DOE's SNF disposal program and the length of time that SNF may need to be stored at the plant site delaying decommissioning.

Decommissioning costs are being recovered in the three rate-making jurisdic-tions based on at least the lower end of the range in the most recent decommissioning study at the time of the last rate proceeding.

However, future results of operations and possibly financial condi-tion could be adversely affected if the costs of spent nuclear fuel disposal and decommissioning continue to increase and if for some reason such costs cannot be recovered.

Environmen al Concerns Hazardous Material By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and spent nuclear fuel.In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls (PCBs)and other hazard-ous and non-hazardous materials.

The Company is currently incurring costs to safely store and dispose of such substances, and additional costs could be incurred to comply with new laws and regulations if enacted.The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA or Superfund legislation) addresses'clean-up of hazard-ous substances at disposal sites and authorizes the United States Environmental Protection Agency a NDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES (Federal EPA)to administer the clean-up programs.As of year-end 1995, ISM is currently involved in litigation with respect to two sites being overseen by the Federal EPA and has been named by the Federal EPA as a"Potentially Responsible Party" (PRP)for three other sites.Information requests have been received for four additional sites which could lead to PRP designation.

IS.M also has received information requests with respect to two sites administered by state authorities.

Liability has been resolved for a number of sites with no signifi-cant effect on results of operations.

The Com-pany's present estimates do not anticipate material cleanup costs for identified sites for which I%M has been declared a PRP.However, if for reasons not currently identified significant costs are required for cleanup, future results of operations and possibly financial condition would be adversely affected unless the costs can be recovered.

Litigation The Company is involved in a number of legal proceedings and claims.While management is unable to predict the outcome of such litigation, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations and/or financial condition.

Resul s of 0 erations Net Income Although revenues increased 2.5%in 1995, net income declined 10.4%to$141 million mainly due to increased operating expenses, including the unfavorable effect of a provision for severance benefits in connection with the realignment of operations and increased federal income tax ex-pense.The increase in net income in 1994 of 21.8%was the result of a retail base rate increase in the Indiana jurisdiction, reduced interest expense due to the retirement of long-term debt, the effect of adopting Statement of Financial Accounting Standards No.109,"Accounting for Income Taxes" (SFAS 109)in 1993 and the retirement in 1994 of a generating plant.Operating Revenues and Energy Sales Increase Operating revenues increased 2.5%in 1995 following a 4%increase in 1994.The changes in revenues are analyzed as follows: Increase (Oecrease)

From Previous Year dollars in millions 1995 1994 Retail: Price Variance Volume Variance$(0.7)$69.8 29.9 30.5 29.2 3.3 100.3 12.9 Mholesale:

Power Pool: Price Variance (7.9)Volume Variance 39.4 Capacity Charges~28.3)32 Unaffiliated Utilities:

Price Variance (12.7)Volume Variance 14.0 1.3 Total Mholesale 4.5 1.3 (3.8)(62.4)2.1~64.)21.1~9.0)12.1~52.0)(12.8)

Other Operating Revenues~1.9)0.4 Total~31.8 2.5~48.7 4.0 The increase in 1995 operating revenues resulted from increased energy usage by retail and unaffili-ated wholesale customers.

Retail energy sales increased 3%reflecting warmer summer weather in 1995 and a colder fourth quarter in 1995 than 1994 and continuing growth in the number of residential, commercial and industrial customers.

While wholesale energy sales increased 34%, wholesale revenues increased only 1%in 1995.The substantial increase in wholesale energy sales was primarily due to a 69%increase in energy sales to the AEP System Power Pool (Power Pool), which are made at cost, reflecting the increased availability of lower cost nuclear generating capac-ity in 1995.During 1995 one nuclear generating unit was out of service for refueling while both units were refueled in 1994.Also contributing to the wholesale energy sales increase were increased sales to unaffiliated entities.Sales to the Com-pany's municipal and cooperative customers and to unaffiliated utilities by the Power Pool which are shared by the Company increased primarily due to the warmer summer and the colder fourth quarter weather in 1995 as compared to 1994.The in-crease in wholesale sales did not lead to a corre-sponding increase in revenues due to reduced capacity credits from the Power Pool and increasing competition in the wholesale energy market.Capacity credits are designed to allocate the cost of the AEP System's generating capacity among the members of the Power Pool based on their relative peak demands and generating reserves.An in-crease in the Company's peak demand during 1995 relative to the peak demand of all Power Pool members caused the decrease in capacity revenues.In 1994 revenues rose 4%largely due to in-creased retail revenues partly offset by a decline in total wholesale revenues.The growth in retail revenues resulted from a$34.7 million annual base rate increase in the Indiana jurisdiction, increased decommissioning expense recoveries in the Michi-gan jurisdiction and a 4%increase in energy sales due to growth in the number of retail customers.

The decline in 1994 wholesale revenues reflected the decrease in energy available for delivery to the Power Pool due to the scheduled refueling and maintenance outages at the Company's two nuclear units in 1994 and lower energy sales by the Power Pool due to mild weather throughout most of 1994.While severe weather in January 1994 and hot June weather increased the Power Pool's short-term wholesale sales in those months, the mild weather throughout the remainder of 1994, com-bined with increased competition in the wholesale market reduced short-term sales for the year.Operating Expenses Increase Total operating expenses increased 5%in 1995 or$48 million reflecting the increased operation of the Company's nuclear units and severance pay accruals.In 1994 total operating expenses rose 4%or$37 million largely due to increased accruals for nuclear decommissioning expense and employee benefits.The significant changes in operating expenses were: Fuel expense increased substantially in 1995 due to a 51%increase in nuclear generation reflecting the increased availability of nuclear generating capacity.During 1995 one unit was out of service for refueling while both units were out of service for refueling in 1994.Fuel expense declined in 1994 due to a significant reduction (43%)in nu-clear generation reflecting the refueling outages partially offset by a 6%increase in fossil genera-tion.The increase in purchased power expense in 1994 reflects increased receipts from the Power Pool due to the nuclear outages and increased purchases from unaffiliated utilities for immediate resale to other unaffiliated utilities.

Other operation expense increased in 1995 primarily due to a provision for severance pay related to the functional realignment of operations and costs related to the development of a new activity based budgeting system.The 1994 in-crease was caused by regulatory-approved in-creases in nuclear decommissioning accruals, accruals for other postretirement benefits commen-surate with rate recovery and expenses related to the closing of the Company's Breed Plant.The increase in federal income taxes attributable to operations in 1995 was primarily due to changes in certain book/tax differences accounted for on a flow-through basis and the effects of favorable accrual adjustments recorded in 1994 in connection with the resolution of the audit of prior years'ax returns.Federal income taxes attributable to operations increased in 1994 due to increased pre-tax operating income.Nonoperating Income and Financing Costs Nonoperating income increased in 1994 reflecting a favorable tax effect from the Breed Plant closing and the unfavorable effect in 1993 of adopting SFAS 109 for nonutility assets and liabilities.

dollars in millions Fuel Purchased Power Other Operation Federal Income Taxes Increase (Oecrease)

From Previous Year 1995 Amount~Amount 1994$21.2 10.5$(18.5)(8.4)(5.8)(4.4)23.0 21.2 10.3 3.5 28.5 10.6 15.7 40.9 6.4 19.9 Interest charges declined in 1994 due to debt repayments and a refinancing program which lowered interest rates.In 1994,$10 million of long-term bonds were retired and$90 million were refinanced.

The full year effects from 1993 refinancings and retirements also contributed to the 1994 reduction.

NDIANA MICHIGAN POWER COMPANy'ND SUBSIDIARIES Construction Spending Effects of Inflation Gross plant and property additions were S151 million in 1995 and$212 million in 1994.Manage-ment estimates construction expenditures for the next three years to be$315 million with no major new generating plant construction planned.The funds for construction of new facilities and im-provement of existing facilities can come from a combination of internally generated funds, short-term and long-term borrowings, preferred stock issuances and investments in common equity by the Company's parent, American Electric Power Co., Inc.However, all of the construction expendi-tures for the next three years are expected to be financed internally.

Liquidity and Capital Resources When necessary the Company generally issues short-term debt to provide for interim financing of capital expenditures that exceed internally generat-ed funds.At December 31, 1995,$372 million of unused short-term lines of credit shared with other AEP System companies were available.

An authorization by the Securities and Exchange Commission limits short-term borrowings to$175 million.Periodic reductions of outstanding short-term debt are made through issuances of long-term debt and preferred stock and through additional capital contributions by the parent company.The Company has regulatory approval to issue up to$150 million of long-term debt.Management expects to use the proceeds of future long-term financings to retire short-term debt, refinance maturing and other long-term debt, refund cumula-tive preferred stock and fund construction expendi-tures.Inflation affects the cost of replacing utility plant and the cost of operating and maintaining such plant.The rate-making process generally limits recovery to the historical cost of assets resulting in economic losses when inflation effects are not recovered from customers on a timely basis.However, economic gains that result from the repayment of long-term debt with inflated dollars partly offset such losses.New Accounting Rules The Financial Accounting Standards Board (FASB)issued a new accounting standard, SFAS 121"Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." The new standard is effective beginning with 1996 accounting periods.The initial implementation of this new standard is not expected to have a signifi-cant impact on the Company.In 1996 the FASB issued an exposure draft"Accounting for Certain Liabilities Related to Clo-sure or Removal of Long-Lived Assets." This document proposes that the present value of any decommissioning or other closure or removal obligation be recorded as a liability when the obligation is incurred.A corresponding asset would be recorded in the plant investment account and recovered through depreciation charges over the asset's life.A proposed transition rule would require that an entity report in income the cumula-tive effect of initially applying the new standard.The Company is currently studying the impact of the proposed rules and evaluating its potential impact.The Company presently exceeds all minimum coverage requirements for issuance of mortgage bonds and preferred stock.The minimum coverage ratios are 2.0 for mortgage bonds and 1.5 for preferred stock.At December 31, 1995, the mortgage bonds and preferred stock coverage ratios were 6.25 and 2.63, respectively.

INDEPENDENT AUDITORS'EPORT To the Shareholders 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, 1995 and 1994, and the related consolidated statements of income, retained earnings, and cash flows for each of the three years in the period ended December 31, 1995.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, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles.

v-/~M L-t-I DELOITTE 5 TOUCHE LLP Columbus, Ohio February 27, 1996 10 Consolidated Statements of Income NDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES 1995 Y rEn D m r 1 1994 (in thousands)

OPERATING REVENUES~$1 28 157~1251 309~$1 202 4 OPERATING EXPENSES: Fuel Purchased Power Other Operation Maintenance Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals Taxes Other Than Federal Income Taxes Federal Income Taxes Total Operating Expenses 222,967 125,413 306,967 141,813 138,814 201,739 131,234 296,625 139,423 136,244 15,644 71,791 54 025 15,644 70,078~38 3 1 077 434 1 029 340 220,206 108,274 268,144 142,637 138,794 15,644 66,805~19 1 992 48 OPERATING INCOME NONOPERATING INCOME (LOSS)INCOME BEFORE INTEREST CHARGES INTEREST CHARGES NET INCOME PREFERRED STOCK DIVIDEND REQUIREMENTS EARNINGS APPLICABLE TO COMMON STOCK 205,723 221,969 210,158 6 272 7 428~2341 211,995 229,397 209,924 70 903 71 895~580 141,092 157,502 129,344 11 791~11 81~14 2 6$129 301 4'145 821~115 088 See Notes to Consolidated Financial Statements.

11 Consolidated Balance Sheets ASSETS D em r 1~1 1994 (in thousands)

ELECTRIC UTILITY PLANT: Production Transmission Distribution General (including nuclear fuel)Construction Work in Progress Total Electric Utility Plant Accumulated Depreciation and Amortization NET ELECTRIC UTILITY PLANT$2,494,834 849,920 644,720 204,909~74 2$2,507,667 867,541 666,810 186,959~@592 4,269,306~1~4 4,319,564~17 1t¹~2567 5 9 2 ff0~96 NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS 4 3619 534 9 OTHER PROPERTY AND INVESTMENTS 1509 4 127 424 CURRENT ASSETS: Cash and Cash Equivalents Accounts Receivable:

Customers Affiliated Companies Miscellaneous Allowance for Uncollectible Accounts Fuel-at average cost Materials and Supplies-at average cost Accrued Utility Revenues Prepayments TOTAL CURRENT ASSETS 13.723 82,434 21,881 11,450 (334)29,093 72,861 43,937~11 1 28 23 9,907 74,491 24,848 20,334 (121)35,802 59,897 40,582~414 2741 4 REGULATORY ASSETS~4'~2 421 7 DEFERRED CHARGES 32 64 31 515 TOTAL$3 928 337$3 878 035 See/Votes to Consolidated hnanoial Statements.

12 IND ICHIGAN POWER COMPANY AND SUBSIDIARIES CAPITALIZATION AND LIABILITIES December 31 1995 1994 (in thousands)

CAPITALIZATION:

Common Stock-No Par Value: Authorized

-2,500,000 Shares Outstanding

-1,400,000 Shares Paid-in Capital Retained Earnings Total Common Shareholder's Equity Cumulative Preferred Stock: Not Subject to Mandatory Redemption Subject to Mandatory Redemption Long-term Debt TOTAL CAPITALIZATION S 56,584 731,102 235 1t37 1,022,793 56,584 733,650 21ljJjg8 1,006,892 52,000 135,000~1034 48 52,000 135,000~29 II87~2243 41 2 123 779 OTHER NONCURRENT LIABILITIES:

Nuclear Decommissioning Other 269,392 184 103 211,963 192 758 TOTAL OTHER NONCURRENT LIABILITIES

~45 495 404 721 CURRf NT LIABILITIES:

Long-term Debt Due Within One Year Short-term Debt Accounts Payable-General Accounts Payable-Affiliated Companies Taxes Accrued Interest Accrued Obligations Under Capital Leases Other 6,053 89,975 37,744 22,962 71,696 16,158 31,776 74 463 140,000 50,600 40,417 22,720 63,621 19,436 39,003~65 40 TOTAL CURRENT LIABILITIES DEFERRED INCOME TAXES DEFERRED INVf STMENT TAX CRf DITS DEFERRED GAIN ON SALE AND LfASfBACK-ROCKPORT PLANT UNIT 2 DEFERRED CREDITS COMMITMENTS AND CONTINGENCIES t Note 3)~5I~27 441 2 612 147~$4!g2 998 2~1)~59 56 2~15 202~14~2 TOTAL$3 928 337$3 878 035 13 Consolidated Statements of Cash Flows YarEn edDcm r 31 19 5~194 (in thousands)

OPERATING ACTIVITIES:

Net Income Adjustments for Noncash Items: Depreciation and Amortization Amortization of Rockport Plant Unit 1 Phase-in Plan Deferrals Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net)Deferred Federal Income Taxes Deferred Investment Tax Credits Changes in Certain Current Assets and Liabilities:

Accounts Receivable (net)Fuel, Materials and Supplies Accrued Utility Revenues Accounts Payable Taxes Accrued Other (net)Net Cash Flows From Operating Activities 148,441 15,644 146,966 15,644 148,270 15,644 8,684 (23,564)(9,004)(18,779)(19,775)(13,877)33,827 (52,631)(8,543)4,121 (6,255)(3,355)(2,431)8,075~23 99)25 49 (7,200)(3,423)(5,940)5,219 9,148~12 14)~2'~)4(4 14,441 14,938 43,913 8,233 38,644~1'~70)~I7(7,$72 S 141,092 S 157,502 S 129,344 INVESTING ACTIVITIES:

Construction Expenditures Long-term Receivable from Customer for Construction of Facilities Proceeds from Sales of Property and Other Net Cash Flows Used For Investing Activities (117,785)(18,733)9 325~127 193)(11 8,094)~238~I1 056)(108,867)KZ5~)0 482)FINANCING ACTIVITIES:

Capital Contributions from Parent Company Issuance of Cumulative Preferred Stock Issuance of Long-term Debt Retirement of Cumulative Preferred Stock Retirement of Long-term Debt Change in Short-term Debt (net)Dividends Paid on Common Stock Dividends Paid on Cumulative Preferred Stock Net Cash Flows Used For Financing Activities Net increase (Decrease) in Cash and Cash Equivalents Cash and Cash Equivalents January 1 Cash and Cash Equivalents December 31 See hfotes to Consolidated Rnancial Statements.

96,819 (141,122)39,375 (110,852)~)1 56)34,618 89,221 (35,798)(101,833)525 (106,608)~1)2 4)10,000 98,776 243,426 (112,300)(392,093)5,875 (108,696)~15 585)3,816~99 7 6,155~72 (3,707)~74~13 723 4 9 907$3 752@1127 34)~131 12)~27 1~57) 7'onsolidated Statements of Retained Earnings DIANA MICHIGAIV POWER COMPANY AIVD SUBSIDIARIES

~199 Year En e Decem r 1~14 (in thousands)

Retained Earnings January 1 Net Income Deductions:

Cash Dividends Declared: Common Stock Cumulative Preferred Stock: 4-1/8%Series 4.56%Series 4.12%Series 5.90%Series 6-1/4%Series 6.30%Series 6-7/8%Series 7.08%Series 7.76%Series 8.68%Series,$2.15 Series$2.25 Series Total Cash Dividends Declared Capital Stock Expense Total Deductions

$216,658~141 0 2~357 7 110,852 495 273 165 2,360 1,875 2,205 2,063 2,124 122,412~21~122 4$177,638 157 502 335 140 106,608 495 273 165 2,360 1,875 1,978 2,063 2,124 317 118,258 224 118 482$171,309~12 44 108,696 495 273 165 374 161 1,799 2,124 2,716 2,517 3,001~6 122,921~4 123 015 Retained Earnings December 31$235 107$216 658 177 638 See IVo(as to Consolidated Rnonciol Stotements.

15 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1.SIGNIFICANT ACCOUNTING POLICIES: Organization Indiana Michigan Power Company (the Company or I%M)is a wholly-owned subsidiary of American Electric Power Company, Inc.(AEP Co., Inc.), a public utility holding company.The Company is engaged in the generation, purchase, transmission and distribution of electric power to 537,000 retail customers in northern and eastern Indiana and a portion of southwestern Michigan.Wholesale electric power is.supplied to neighboring utility systems.As a member of the American Electric Power (AEP)System Power Pool (Power Pool)and a signatory company to the AEP Transmission Equalization Agreement, its facilities are operated in conjunction with the facilities of certain other AEP affiliated utilities as an integrated utility system.The Company has two wholly-owned subsidiar-ies, which are consolidated in these financial statements, Blackhawk Coal Company and Price River Coal Company, that were formerly engaged in coal-mining operations.

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

Price River Coal Company, which owns no land or mineral rights, is inactive.Regulation As a subsidiary of AEP Co., Inc., I@M is subject to regulation by the Securities and Exchange Com-mission (SEC)under the Public Utility Holding Com-pany Act of 1935 (1935 Act).Retail rates are regulated by the Indiana Utility Regulatory Commis-sion (IURC)and the Michigan Public Service Com-mission.The Federal Energy Regulatory Commis-sion (FERC)regulates wholesale rates.Principles of Consolidation The consolidated financial statements include ItkM and its wholly-owned subsidiaries.

Significant intercompany items are eliminated in consolidation.

Basis of Accounting As a cost-based rate-regulated entity, IRM's financial statements reflect the actions of regulators that result in the recognition of revenues and expenses in different time periods than enterprises that are not cost-based rate regulated.

In accor-dance with Statement of Financial Accounting Standards (SFAS)No.71,"Accounting for the Effects of Certain Types of Regulation," regulatory assets and liabilities are recorded to reflect the economic effects of regulation.

Use of Estimates The preparation of these financial statements in conformity with generally accepted accounting principles requires in certain instances the use of management's estimates.

Actual results could differ from those estimates.

Utility Plant Electric utility plant is stated at original cost and is generally subject to first mortgage liens.Addi-tions, major replacements and betterments are added to the plant accounts.Retirements from the plant accounts and associated removal costs, net of salvage, are deducted from accumulated depreci-ation.The costs of labor, materials and overheads incurred to operate and maintain utility plant are included in operating expenses.Allowance for Funds Used During Construction (AFUDCJ AFUDC is a noncash nonoperating income item that is recovered with regulator approval over the service life of utility plant through depreciation and represents the estimated cost of borrowed and equity funds used to finance construction projects.The amounts of AFUDC for 1995, 1994 and 1993 were not significant.

16 IANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Functional Class~of Pro e t Production:

Steam-Huclear Steam-Fossil-Fired Hydroelectric-Conventional Transmission Distribution General Compost te Annual Rates 3.4X 4.4X 3.2X 1.9X 4.2X 3.8X Amounts to be used for demolition of non-nuclear plant are presently recovered through depreciation charges included in rates.The accounting and rate-making treatment afforded nuclear decommissioning costs and nuclear fuel disposal costs are discussed in Note 3.Cash and Cash Equivalents Cash and cash equivalents include temporary cash investments with original maturities of three months or less.Operating Revenues Revenues include the accrual of electricity con-sumed but unbilled at month-end as well as billed revenues.Fuel Costs Depreciation and AmortizatI'on

'Depreciation is provided on a straight-line basis over the estimated useful lives of utility plant and is calculated largely through the use of composite rates by functional class as follows: Levelization of Nuclear Refueling Outage Costs Incremental operation and maintenance costs associated with refueling outages at the Donald C.Cook Nuclear Plant (Cook Plant)are deferred for amortization over the period (generally eighteen months)beginning with the commencement of an outage and ending with the beginning of the next outage.Income Taxes The Company follows the liability method of accounting for income taxes as prescribed by SFAS 109,"Accounting for Income Taxes." Under the liability method, deferred income taxes are provided for all temporary differences between book cost and tax basis of assets and liabilities which will result in a future tax consequence.

Where the flow-through method of accounting for temporary differences is reflected in rates, regulatory assets and liabilities are recorded in accordance with SFAS 71.Investment Tax Credits Based on directives of regulatory commissions, the Company reflected investment tax credits in rates on a deferral basis.Commensurate with rate treatment deferred investment tax credits are being amortized over the life of the related plant invest-ment.The Company's policy with regard to invest-ment tax credits for nonutility property was to practice the flow-through method of accounting.

Debt and Preferred Stock Fuel costs are matched with revenues in accor-dance with rate commission orders.Revenues are accrued related to unrecovered fuel in both retail jurisdictions and for replacement power costs in the Michigan jurisdiction until approved for billing.If the Company's earnings exceed the allowed return in the Indiana jurisdiction, the fuel clause mecha-nism provides for the refunding of the excess earnings to ratepayers.

Wholesale jurisdictional fuel cost changes are expensed and billed as incurred.Gains and losses on reacquired debt are deferred arid amortized over the remaining term of the reacquired debt in accordance with rate-making treatment.

If the debt is refinanced the reacquisi-tion costs are deferred and amortized over the term of the replacement debt commensurate with their recovery in rates.In accordance with rate-making treatment debt discount or premium and debt issuance expenses are amortized over the term of the related debt, with the amortization included in interest charges.17 Redemption premiums paid to reacquire preferred stock are deferred, debited to paid-in capital and amortized to reduce retained earnings in accordance with rate-making treatment.

The excess of par value over costs of preferred stock reacquired to meet sinking fund requirements is credited to paid-in capital.Nuclear Decommissioning and Spent Nuclear Fuel Disposal Trust Funds Securities held in trust funds for decommissioning nuclear facilities and for the disposal of spent nuclear fuel are recorded at market value in accor-dance with SFAS 115,"Accounting for Certain Investments in Debt and Equity Securities." Securi-ties in the trust funds have been classified as available-for-sale due to their long-term purpose.Due to the rate-making process, adjustments for unrealized gains and losses are not reported in equity but result in adjustments to regulatory assets and liabilities.

Other Property and Investments Other property and investments are stated at Cost.Reclassifications Certain prior-period amounts were reclassified to conform with current-period presentation.

2.EFFECTS OF REGULATION AND PHASE-IN PLANS: the Company's business'o longer met these requirements regulatory assets and liabilities would have to be written off for that portion of the busi-ness.Regulatory assets and liabilities are comprised of the following:

December 31 1995 1994 (in thousands)

Regulatory Assets: Amounts Due From Customers for Future Income Taxes Department of Energy Decontamination and Oecocmissioning Assessment Rate Phase-in Plan Deferrals Nuclear Refueling Outage Cost Levelization Unamortized Loss On Reacquired Debt Other Total Regulatory Assets$309,640$308,831 48,862 27,515 51,896 43,159 23,467 32,151 20,827 20 214~458 525 18,472 27 500~402 107 Regulatory Liabilities:

Deferred Investment Tax Credits$155,202$164,206 Other*1 576 350 Total Regulatory tiaailitiaa

~t56 770~164 556*Included in Deferred Credits on Consolidated Balance Sheets.The Rockport Plant consists of two 1,300 mega-watt (mw)coal-fired units.IS.M and AEP Generat-ing Company (AEGCo), an affiliate, each own 50%of one unit (Rockport 1)and lease a 50%interest in the other unit (Rockport 2)from unaffiliated lessors under an operating lease.The gain on the sale and leaseback of Rockport 2 was deferred and is being amortized, with related taxes, over the initial lease term which expires in 2022.The consolidated financial statements include assets and liabilities recorded in accordance with regulatory actions in order to match expenses with the related revenues included in cost-based regu-lated rates.Regulatory assets are expected to be recovered in future periods through the rate-making process and regulatory liabilities are expected to reduce future cost recoveries.

The Company has reviewed all the evidence currently available and concluded that it continues to meet the require-ments to apply SFAS 71.In the event a portion of Rate phase-in plans in the Company's Indiana and FERC jurisdictions for its share of Rockport 1 provide for the recovery and straight-line amortiza-tion through 1997 of prior-year deferrals.

Unamor-tized deferred amounts under the phase-in plans were$27.5 million and$43.2 million at December 31, 1995 and 1994, respectively.

Amortization was$16 million in 1995, 1994 and 1993.18 IANA MICHIGAN POWER COMPANY AND SUBSIDIARIES 3.COMMITMENTS AND CONTINGENCIES:

Construction and Other Commitments Substantial construction commitments have been made.Such commitments do not include any expenditures for new generating capacity.The aggregate construction program expenditures for 1996-1998 are estimated to be$315 million.Long-term fuel supply contracts contain clauses that provide for periodic price adjustments.

The retail jurisdictions have fuel clause mechanisms that provide for recovery of changes in the cost of fuel with the regulators'eview and approval.The contracts are for various terms, the longest of which extends to 2014, and contain various claus-es that would release the Company from its obliga-tion under certain force majeure conditions.

Unit Power Agreements The Company is committed under unit power agreements to purchase 70%of AEGCo's 1,300 mw Rockport Plant capacity unless it is sold to unaffiliated utilities.

AEGCo has one long-term contract with an unaffiliated utility that expires in 1999 for 455 mw of Rockport Plant capacity.The Company sells under contract up to 250 mw of Rockport Plant capacity to an unaffiliated utility.The contract expires in 2009.territory.

The lower court had dismissed the case filed under a provision of Indiana law that allows a utility to seek damages equal to the gross revenues received by the Company for rendering service in the designated service territory of another utility.The Company is involved in a number of other legal proceedings and claims.While management is unable to predict the ultimate outcome of litiga-tion, it is not expected that the resolution of these matters will have a material adverse effect on the results of operations or financial condition.

Nuclear Plant I@M owns and operates the two-unit 2,110 mw Cook Plant under licenses granted by a regulatory authority.

The operation of a nuclear facility in-volves special risks, potential liabilities, and specific regulatory and safety requirements.

Should a nuclear incident occur at any nuclear power plant facility in the United States, the resultant liability could be substantial.

Sy agreement IS.M is partially liable together with all other electric utility compa-nies that own nuclear generating units for a nuclear power plant incident.In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery is not possible, results of opera-tions and financial condition would be negatively affected.Nuclear Incident Liability Litigation In September 1995, the Indiana Supreme Court ruled in favor of the Company when it denied an appeal of a March 1995 opinion from the Court of Appeals of Indiana.The appeals court had upheld and affirmed a lower court's decision.The case resulted from an earlier Supreme Court of Indiana decision which overruled a lower court decision and voided an IURC order assigning a customer to the Company.The Company had received approxi-mately$29 million in gross revenues from the customer which was not in the Company's service Public liability is limited by law to$8.9 billion should an incident occur at any licensed reactor in the United States.Commercially available insur-ance provides$200 million of coverage.In the event of a nuclear incident at any nuclear plant in the United States the remainder of the liability would be provided by a deferred premium assess-ment of$79.3 million on each licensed reactor payable in annual installments of$10 million.As a result, IRM could be assessed$158.6 million per nuclear incident payable in annual installments of$20 million.The number of incidents for which payments could be required is not limited.19 Nuclear insurance pools and other insurance policies provide$3.6 billion of property damage, decommissioning and decontamination coverage for Cook Plant.Additional insurance provides coverage for extra costs resulting from a prolonged acciden-tal Cook Plant outage.Some of the policies have deferred premium provisions which could be trig-gered by losses in excess of the insurer's resources.

The losses could result from claims at the Cook Plant or certain other non-affiliate nu-clear units.The Company could be assessed up to$40.9 million annually under these policies.Spent Nuclear Fuel Disposal Federal law provides for government responsibility for permanent spent nuclear fuel disposal and assesses nuclear plant owners fees for spent fuel disposal.A fee of one mill per kilowatthour for fuel consumed after April 6, 1983 is being collected from customers and remitted to the U.S.Treasury.Fees and related interest of$163 million for fuel consumed prior to April 7, 1983 have been record-ed as long-term debt.IRM has not paid the govern-ment the pre-April 1983 fees due to various factors including continued delays and uncertainties related to the federal disposal program.At December 31, 1995, funds collected from customers to eventually pay the pre-April 1983 fee and related earnings including accrued interest approximated the liability.

Decommissioning and Low Level Waste Accumula-tion Disposal Decommissioning costs are accrued over the service life of the Cook Plant.The licenses to operate the two nuclear units expire in 2014 and 2017.After expiration of the licenses the plant is expected to be decommissioned through disman-tlement.The Company's latest estimate for decom-missioning and low level radioactive waste accumulation disposal costs range from$634 million to$988 million in 1993 nondiscounted dollars.The wide range is caused by variables in assumptions including the estimated length of time spent nuclear fuel must be stored at the plant subsequent to ceasing operations which depends on future developments in the federal government's 4.RELATED PARTY TRANSACTIONS:

Benefits and costs of the System's generating plants are shared by members of the Power Pool.The Company is a member of the Power Pool.Under the terms of the System Interconnection Agreement, capacity charges and credits are de-signed to allocate the cost of the System's capacity among the Power Pool members based on their relative peak demands and generating reserves.Power Pool members are also compensated for the out-of-pocket costs of energy delivered to the Power Pool and charged for energy received from the Power Pool.The Company is a net supplier to the pool and, therefore, receives net capacity credits from the Power Pool.Operating revenues includes revenues for supply-ing energy and capacity to the Power Pool as follows: Year Ended Oecember 31 1995 1994 1993 (in thousands)

Capacity Revenues Energy Revenues Total$59,918$88,183$86,050 83 799 52 274 118 533~l43 717~l40 457~204 583.spent nuclear fuel disposal program.Continued delays in the federal fuel disposal program can result in increased decommissioning costs.Decommissioning costs are being recovered in the three rate-making jurisdictions based on at least the lower end of the range in the most recent decom-missioning study at the time of the last rate pro-ceeding.The Company records decommissioning costs in other operation expense and records a noncurrent liability equal to the decommissioning cost recovered in rates which was$30 million in 1995,$26 million in 1994 and$13 million in 1993.Decommissioning amounts recovered from custom-ers are deposited in external trusts.Trust fund earnings increase the fund assets and the recorded liability and decrease the amount to be recovered from ratepayers.

At December 31;1995 the Company has recognized a decommissioning liability of$269 million.20 IANA MICHIGAN POWER COMPANY AND SUBSIDIARIES Purchased power expense includes charges of$25.4 million in 1995,$33.1 million in 1994 and$20.9 million in 1993 for energy received from the Power Pool.Power Pool members share in wholesale sales to unaffiliated utilities made by the Power Pool.The Company's share of the Power Pool wholesale sales included in operating revenues were$52.6 million in 1995,$54.1 million in 1994 and$57 million in 1 993.In addition, the Power Pool purchases power from unaffiliated companies for immediate resale to other unaffiliated utilities.

The Company's share of these purchases was included in purchased power ex-pense and totaled$10.7 million in 1995,$14.2 million in 1994 and$5.1 million in 1993.Revenues from these transactions including a transmission fee are included in the above Power Pool wholesale operating revenues.The cost of power purchased from AEGCo, an affiliated company that is not a member of the Power Pool, was included in purchased power expense in the amounts of$85.2 million,$82.4 million and$78.9 million in 1995, 1994 and 1993, respectively.

The Company operates the Rockport Plant and bills AEGCo for its share of operating costs.AEP System companies participate in a transmis-sion equalization agreement.

This agreement combines certain AEP System companies'nvest-ments in transmission facilities and shares the costs of ownership in proportion to the System compa-nies'espective peak demands.Pursuant to the terms of the agreement, other operation expense includes equalization credits of$46.7 million,$50.3 million and$47.4 million in 1995, 1994 and 1993, respectively.

Revenues from providing barging services were recorded in nonoperating income as follows: Year Ended December 31 1995 1994 1993 (in thousands)

Affiliat,ed Companies$23,160$24,001$21,332 Unaffiltaaed Cnepanlea 5 992 5 021 5 757 Total~30 152~29 022~27 099 American Electric Power Service-Corporation

{AEPSC)provides certain managerial and profes-sional services to AEP System companies.

The costs of the services are billed by AEPSC on a direct-charge basis to the extent practicable and on reasonable bases of proration for indirect costs.The charges for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP Co., Inc.Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered.AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act.5.BENEFIT PLANS: The Company and its subsidiaries participate in the AEP System pension plan, a trusteed, noncon-tributory defined benefit plan covering all employ-ees meeting eligibility requirements.

Benefits are based on service years and compensation levels.Pension costs are allocated by first charging each System company with its service cost and then allocating the remaining pension cost'in proportion to its share of the projected benefit obligation.

The funding policy is to make annual trust fund contri-butions equal to the net periodic pension cost up to the maximum amount deductible for federal income taxes, but not less than the minimum required contribution in accordance with the Employee Retirement Income Security Act of 1974.Net pension costs for the years ended December 31, 1995, 1994 and 1993 were$2.7 million,$5 million and$4.7 million, respectively.

An employee savings plan is offered which allows participants to contribute up to 17%of their sala-ries into various investment alternatives, including AEP Co., lnc.common stock.An employer match-ing contribution, equaling one-half of the employees'ontribution to the plan up to a maxi-mum of 3%of the employees'ase salary, is invested in AEP Coed Inc.common stock.The employer's annual contributions totaled$3.9 million in 1995 and 1994 and S3.5 million in 1993.21 Postretirement benefits other than pensions (OPEB)are provided for retired employees under an AEP System plan.Substantially all employees are eligible for postretirement health care and life insurance if they have at least 10 service years and are age 55 or older when employment terminates.

SFAS 106,"Employers'ccounting for Postretirement Benefits Other Than Pensions" was adopted in January 1993 for the Company's aggre-gate liability for OPEB.SFAS 106 requires the accrual during the employee's service years of the present value liability for OPEB costs.Costs for the accumulated postretirement benefits earned and not recognized at adoption are being recognized, in accordance with SFAS 106, as a transition obliga-tion over 20 years.OPEB costs are determined by the application of AEP System actuarial assump-tions to each operating company's employee complement.

The annual accrued OPEB costs for employees and retirees required by SFAS 106, which includes the recognition of one-twentieth of the prior service transition obligation, were$13.6 million in 1995,$13.2 million in 1994 and$12.4 million in 1993.The Company received approval from the IURC to recover the increased OPEB costs resulting from SFAS 106.In the Michigan and wholesale juris-dictions, the Company received authority to defer under certain conditions the increased OPEB costs which are not being currently recovered in rates.Future recovery of any deferrals and increased OPEB costs will be sought in the next base rate filings.At December 31, 1995 and 1994,$6.7 million of incremental OPEB costs were deferred.As a result of SFAS 106, a Voluntary Employees Beneficiary Association (VEBA)trust fund for OPEB benefits was established and a corporate owned life insurance (COLI)program was implemented to lower the net OPEB costs.The insurance policies have a substantial cash surrender value which is recorded, net of equally substantial policy loans, in other property and investments.

Legislation was passed by Congress which would have significantly reduced the tax benefits of a COLI program in the future.The legislation containing this provision was vetoed by the President.

At this time it is uncertain if legislation repealing certain tax benefits for COLI programs will be enacted.If enacted this legislation would negatively impact the effective-ness of the COLI program as a funding and cost reduction mechanism.

The funding policy is to make VEBA trust fund contributions equal to the increase in OPEB costs resulting from the implementation of SFAS 106.These contributions include amounts collected from ratepayers and the net earnings from the COLI pro-gram.Contributions to the VEBA trust fund were$10.3 million in 1995, 86.6 million in 1994 and 81.3 million in 1993.6.SUPPLEMENTARy INFORMATION:

Year Ended Oecember 31 1995 1994 1993 (in thousands)

Cash was paid for: Interest (net of capitalized amounts)$71,457$68,946$82,509 Income Taxes 88,675 85,854 68,303 Noncash Acquisitions Under Capital Leases were 32,073 92,199 15,467 In connection with the sale of western coal land and equipment the Company will receive cash payments from the buyer of$31.6 million over a six year period which has been recorded at a net present value of$26.9 million.In connection with construction of facilities to provide service to a new customer the Company will receive cash payments of$20.9 million plus accrued interest over 20 years.22 IANA MICHIGAN POWER COMPANY AND SUBSIDIARIES 7.FEDERAL INCOME TAXES: The details of federal income taxes as reported are as follows: 1995 Year Ended December 31 1994 (in thousands) 1993 Charged (Credited) to Operating Expenses (net): Current Deferred Deferred Investment Tax Credits Total Charged (Credited) to Nonoperating Income (net): Current Deferred Deferred Investment Tax Credits Total Total Federal Income Taxes as Reported$75,686 (13,732)~7929)54 025 12,872 (9,832)~)075)1 965~55 990$64,565 (18,057)~8)55)38 353 1,390 (1,718)~5722)~6050)~32 303$93,974 (53,685)~8308)31 981 6,026 1,054~235)6 845~38 826 1995 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 (in thousands)

Net Income Federal Income Taxes Pre-tax Book Income Federal Income Tax on Pre-tax Book Income at Statutory Rate (35K)Increase (Decrease) in Federal Income Tax Resulting From the Following Items: Depreciation Adoption of SFAS 109 Corporate Owned Life Insurance Nuclear Fuel Disposal Costs Amortization of Deferred Investment Tax Credits (net)Other Total Federal Income Taxes as Reported Effective Federal Income Tax Rate$141,092 55 990~)97 082$68,979 8,954 (5,187)(3,060)(9,004)~4692)~55 990 28.4'A$157,502 32 303~)89 805$66,432 (1,033)(4,521)(4,498)(13,875)~10 202)~32 303 17.0X$129,344 38 826~168 170$58,860 (747)5,271 (4,697)(2,432)(8,543)~8886)~38 826 23.I'A 23 The following tables show the elements of the net deferred tax liability and the significant temporary differences that gave rise to it: December 31 1995 1994 (in thousands)

Deferred Tax Assets$221,604$198,750 0eferred Tax Liabllitlea

~833 751)~833 652)liat 0eferred Tax Llabilitlea

~612 147)~634 902)At December 31, 1995 and 1994 the fair values of trust investments were$434 million and$353 million, respectively.

Accumulated gross unrealized holding gains and losses were$19.1 million and$1.0 million, respectively, at December 31, 1995.The change in market value during 1995 and 1994 was a$24.9 million net holding gain and a$27.1 million net holding loss, respectively.

Temporary Differences in Tax Dollars: Property Related Temporary Differences Amounts Due From Customers For Future Federal Income Taxes Deferred State Income Taxes Deferred Net Gain-Rockport Plant Unit 2 All Other (net)Total Net Deferred Tax Liabilities

$(490,986)$(498,124)(83,277)(71,712)(81,812)(71,712)34,941 36,239~))13)~)9 493)~6)2 147)~634 902)The trust investments'ost basis by security type were: December 31 1995 1994 (in thousands)

Treasury bonds Tax-exempt bonds Equity securities Cash, cash equivalents and interest accrued Total$14,963 336,073 24,101 40 356~4)5 493$997 332,098 1,665 25 304~360 064 Proceeds from sales and maturities of securities of$78.2 million during 1995 resulted in$1.4 million of realized gains and$0.3 million of realized losses.Proceeds from sales and maturities of securities of$20l1 million during 1994 resulted in$52,000 of realized gains and$155,000 of realized losses.The cost of securities for determining realized gains and losses is original acquisition cost including amor-tized premiums and discounts.

The Company and its subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System.The allocation of the AEP System's current consolidated federal income tax to the System companies is in accor-dance with SEC rules under the 1935 Act.These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense.The tax loss of the System parent company, AEP Coed Inced is allocated to its subsidiaries with taxable income.With the exception of the loss of the parent company, the method of allocation approxi-mates a separate return result for each company in the consolidated group.The AEP System has settled with the Internal Revenue Service (IRS)all issues from the audits of the consolidated federal income tax returns for the years prior to 1991.Returns for the years 1991 through 1993 are presently being audited by the IRS.In the opinion of management, the final settlement of open years will not have a material effect on results of operations.

8.FAIR VALUE OF FINANCIAL INSTRUMENTS:

Nuclear Trust Funds Recorded at Market Value The trust investments are recorded at market value in accordance with SFAS 115 and consist primarily of tax-exempt municipal bonds.At December 31, 1995, the year of maturity of trust fund investments, other than equity securities, was: (in thousands) 1996 1997-2000 2001-2005 After 2005 Total$55,748 96,882 162,563 76 199~39)392 Other Financial Instruments Recorded at Historical Cost The carrying amounts of cash and cash equiva-lents, accounts receivable, short-term debt, and accounts payable approximate fair value because of the short-term maturity of these instruments.

Fair values for preferred stocks subject to mandatory redemption were$140 million and$117 million and for long-term debt were$1.1 billion and$1.0 billion at December 31, 1995 and 1994, respectively.

The carrying amounts for preferred stock subject to mandatory redemption were$135 million at each year end and for long-term debt were$1.0 billion IANA MICHIGAN POWER COMPANY AND SUBSIDIARIES 9.LEASES: Leases of property, plant and equipment are for periods up to 35 years and require payments of related property taxes, maintenance and operating costs.The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.Properties under capital leases and related obliga-tions recorded on the Consolidated Balance Sheets are as follows: Oecember 31 1995 1994 (in thousands)

Electric Utility Plant: Production Oistribution General: Nuclear Fuel (net of amortization)

Other Total Electric Utility Plant Accumulated Amortization Net Electric Utility Plant$9,346 14,753 69,442 54 554 148,095 24 933 123 162$8,371 14,717 89,478 53 781 166,347 27 225 139 122 and$1.1 billion at December 31, 1995 and 1994, res'pectively.

Fair values are based on quoted market prices for the same or similar issues and the current dividend or interest rates offered for instru-ments of the same remaining maturities.

The carrying amount of the pre-April 1983 spent nuclear fuel disposal liability approximates the Company's best estimate of its fair value.The noncurrent portion of capital lease obliga-tions is included in other noncurrent liabilities.

Properties under operating leases and related obligations are not included in the Consolidated Balance Sheets.Operating Leases Amortization of Capital Leases interest on Capital Leases Total Rental Costs$96,472$104,519$103,884 45,843 30,875 46,063 9 987 7 643 8 873~752 302~743 037~758 820 Future minimum lease payments consisted of the following at December 31, 1995: Non-Cancelable Capital Operating Leases Leases (in thousands) 1996 1997 1998 1999 2000 Later Years$13,765 12,518 10,620 9,389 8,275 44 362$98,357 96,593 91,454 91,312 91,165 1 840 723 Total Future Minimum Lease Payments 98,929(a)~2 309 604 Lease rentals are generally charged to operating expenses in accordance with rate-making treat-ment.The components of rental costs are as follows: Year Ended Oecember 31 1995 1994 1993 (in thousands)

Other Property Accumulated Amortization Net Other Property Net Properties under Capital Leases Capital Lease Obligations:

Noncurrent Liability Liability Oue Mithin One Year Total Capital Lease Obligations 22,361 3 017 19 344 142 506$110,730 31 776~742 506 15,842 2 375 13 467 152 589$113,586 39 003~752 589 Less Estimated Interact Element 25 865 Estimated Present Value of Future Minimum Lease Payments Unamortized Nuclear Fuel Total 73,064 69 442~742 506 (a)Excludes nuclear fuel rentals which are paid in proportion to heat produced and carrying charges on the unamortized nuclear fuel balance.There are no minimum lease payment requirements for-leased nuclear fuel.25 10.CUMULATIVE PREFERRED STOCK: At December 31, 1995, authorized shares of cumulative preferred stock were as follows: Par Value$100 25 Shares Authorized 2,250,000 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 1994 the Company redeemed and cancelled 350,000 shares of the 7.76%series.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:

Series 4-1/BX 4.56K 4.12'.OBIO Call Price December 31, 1995$106.125 102 102.728 101.85 Par Value$100 100 100 100 Shares Outstanding Oecember 31 1995 120,000 60,000 40,000 300,000 Amount Oecember 31 1995 1994 (in thousands)

$12,000$12,000 6,000 6,000 4,000 4,000 3D ODO 30 ODO~52 OOD~52 ODO B.Cumulative Preferred Stock Subject to Mandatory Redemption:

Series(a)Par Value Shares Outstanding December 31 1995 Amount Oecember 31 1995 1994 (in thousands) 5.90!(b)6-1/4X(c)6.30K (d)6-7/BX(e)$100 100 100 100 400,000 300,000 350,000 300,000$40,000 30,000 35,000 30 ODD~235 000$40,000 30,000 35,000 30 ODD~135 000 (a)Not callable until after 2002.Thoro are 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 shores each year and tho redemption of tho remaining shares outstanding on January 1, 2009, in each case at S100 pef share.(c)Shares issued November 1993.Commencing in 2004 and continuing through tho year 2008, a sinking fund will require the redemption of 15,000 shares each year and tho redemption of the remaining shares outstanding on April 1, 2009, in each case at$100 por 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 S100 per 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 shores each year and the redemption of the remaining shares outstanding on April 1, 2008, in each case at S100 per share.26 0 ANA MICHIGAN POWER COMPANY AND SUBSIDIARIES 11.LONG-TERIVI DEBT AND LINES OF CREDIT: Long-term debt by major category was out-standing as follows: December 31 1995 1994 (in thousands)

First Mortgage Bonds Installment Purchase Contracts Other Long-term Oebt(a)Notes Payable to Banks Sinking Fund Oebentures(b)

$562,017$561,770 308,971 163,060 6 053 308,087 153,977 40,000 6 053 1,040,101 1,069,887 Less Portion Oue Within One Year Total 6 053 140 000~1034 040~929 807 (a)Nuc(ear Fuel Disposal Costs including interest accrued.See Nots 3.(b)Called for redemption on March 1, 1996.First mortgage bonds outstanding were as fol-lows: Oecember 31 1995 1994 (in thousands)

I Rate Oue 7 1998-May 1 7.30 1999-Oecember 15 7.63 2001-June 1 7.60 2002-November 1 7.70 2002-Oecember 15 6.80 2003-July 1 6.55 2003-October 1 6.10 2003-November 1 6.55 2004-Harch I 9.50 2021-Hay 1 9.50 2021-Hay 1 9.50 2021-May 1 8.75 2022-May 1 8.50 2022-December 15 7.80 2023-July 1 7.35 2023-October 1 7.20 2024-February 1 7.50 2024-March I Unamortized Oiscount (net)$35,000 35,000 40,000 50,000 40,000 20,000 20,000 30,000 25,000 10,000 10,000 20,000 50,000 75 F 000 20,000 20,000 40,000 25,000~2903)$35,000 35,000 40,000 50,000 40,000 20,000 20,000 30,000 25,000 10,000 10,000 20,000 50,000 75,000 20,000 20,000 40,000 25,000~3230)Total~562 017~56)770 Certain indentures relating to the first mortgage bonds contain improvement, maintenance and re-placement provisions requiring the deposit of cash or bonds with the trustee, or in lieu thereof, certifi-cation of unfunded property additions.

Installment purchase contracts have been entered into in connection with the issuance of pollution control revenue bonds by governmental authorities as follows: Oecember 31 1995 1994 (in thousands)

~Rate Oue City of Lawrenceburg, Indiana: 7 2015-April 1 5.9 2019-November 1 City of Rockport, Indiana: 9-1/4 2014-August 1 6-3/4 2014-August 1 (a)2014-August 1 7.6 2016-Harch 1 6.55 2025-June 1 (b)2025-June 1 City of Sullivan, Indiana: 5.95 2009-Hay 1 Unamortized Oiscount Less Portion Oue Within One Year$25,000 52,000 50,000 40,000 50,000 50,000 45,000~3029)308,971$25,000 52,000 50,000 50,000 50,000 40,000 45,000~3913)308,087 Total 100 000~300 971~200 007 (a)The variable interest rate is determined weekly.The average weighted interest rate was 4.6X for 1995 and 3.8X for 1994.(b)The adjustable interest rate can be a daily, weekly, contnercial paper or term rate as designated by the Company.Initially, a weekly rate was selected during 1995 which ranged from 2.9X to SX and averaged 4.0X.Under the terms of certain installment purchase contracts, the Company is required to pay amounts sufficient to enable the cities to pay interest on and the principal (at stated maturities and upon mandatory redemption) of related pollution control revenue bonds issued to finance the construction of pollution control facilities at certain generating plants.On the two variable rate series the principal is payable at the stated maturities or on the demand of the bondhoiders at periodic interest adjustment dates which occur weekly.The variable rate bonds due in 2014 are supported by a bank letter of credit which expires in 2002.I&M has agreements that provide for brokers to remarket the variable rate bonds due in 2025 tendered at interest adjustment dates.In the event certain bonds cannot be remarketed, I&M has a standby bond purchase agreement with a bank that 27 provides for the bank to purchase any bonds not remarketed.

The purchase agreement expires in 2000.Accordingly, the variable rate installment purchase contracts have been classified for repayment purposes based on the expiration dates of the standby purchase agreement and the letter of credit.At December 31, 1995, annual long-term debt payments, excluding premium or discount, are as follows: Princi al Amount (in thousands) 1996 1997 1998 1999 2000 Later Years Total$6,053 35,000 35,000 50,000 920 060 1 046 113 Short-term debt borrowings are limited by provi-sions of the 1935 Act to$175 million.Lines of credit are shared with AEP System companies and at December 31, 1995 and 1994 were available in the amounts of$372 million and$558 million, respectively.

Commitment fees of approximately 1/8 of 17%of the unused short-term lines of credit are paid each year to the banks to maintain the lines of credit.Outstanding short-term debt con-sisted of: Year-end Balance Weighted Outstanding Average 12.COMMON SHAREHOLDER'S EQUITY'he Company received from AEP Co., Inc.a cash capital contribution of$10 million in 1993 which was credited to paid-in capital~In 1995, 1994 and 1993 net charges to paid-in capital of$2,548,000,$422,000 and$1,224,000, respectively, repre-sented expenses of issuing and retiring cumulative preferred stock.There were no other transactions affecting the common stock and paid-in capital accounts in 1995, 1994 and 1993.13.UNAUDITED QUARTERLY FINANCIAL INFOR-IVIATION: Iiuarterly Periods tnded Operating Operating Revenues Income (in thousands)

Net Income 1995 Harch 31 June 30 September 30 December 31$327,177 307,820 334,846 313,314$56,311 51,386 54,400 43,626$38,388 33,780 37,404 31,520 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, 1995,$5.9 million of retained earnings were restricted.

Regulatory approval is required to pay dividends out of paid-in capital.December 31, 1995: Note Payable Comnercial Paper Total December 31, 1994: Comnercial Paper 50 600 6.3X$52,200 6.1X 37 775 6.1~59 975 6.7 1994 Harch 31 June 30 September 30 December 31 337,921 310,104 317,061 286,223 58,875 54,691 55,469 52,934 44,976 37,281 37,736 37,509 28 IANA MICHIGAN POWER COMPANY AND SIJBSIDIARIES OPERATING STATISTICS 1995 1994 1993 1992 1991 OPERATING REVENUES (In thousands):

Retail: Residential:

Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)Total Revenues from Energy Sales Provision for Refunds of Revenues Collected in Prior Years Total Net of Provision for Refunds Other Total Operating Revenues 239,266 S 227,358 S 205,315$209,682 S 206,257 109 504~107 52 97 568 98 553~289 348,770 334,881 302,883 308,235 299,546 256,319 247,938 220,938 228,285 216,303 298,256 291,527 250,939 267,643 241,858~42 i~1~559~11 1 2~12 1 2 909,827 880,662 780,353 815,175 769,827~57 441 352 889 404 910 369 379 436 083 1,267,268 1,233,551 1,185,263 1,184,554 1,205,910~7551~40381 5 176 1,267,268 1,233,551 1,184,508 1,180,516 1,211,086 15 889~17 75 18 135 16 239~14 7 1 41 283 157 41 251 309$1 202 643~1196 755 41 225 867 SOURCES AND SALES OF ENERGY (in millions of kilowatthours):

Sources: Net Generated:

Fossil Fuel Nuclear Fuel Hydroelectric Total Net Generated Purchased and Power Pool Total Sources Less: Losses, Company Use, Etc.Net Sources 12,850 13,999~8 26,935 5 871 32,806~17 0 31 106 13,022 9,291 22,408~57 7 28,165 1 398 26 767 12,236 16,313 100 28,655 4 879 33,534 1 349 32 185 11,597 6,418 10(}18,115 9 342 27,457~14 6 25 991 12,109 15,524 1II9 27,742~52 7 32,979~14 4 31 525 Sales: Retail: Residential:

Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)Total Sales 3,390 1 768 5,158 4,300 6,582 82 16,122 14 984 31 106 3,210 1 727 4,937 4,148 6,453 82 15,620 11 147 26 767 3,178 1 706 4,884.3,977 6,025 83 14,969~17 21 32 185 3,001~16 3 4,634 3,747 5,685 194 14,260~117 1 25 991 3,166~125 4,791 3,726 5,382~23 14,132~17',~9 31 525 29 OPERATING STATISTICS (Concluded) 1995 1 94 199 AVERAGE COST OF FUEL CONSUMED (in cents): Per Million Btu: Coal Nuclear Overall Per Kilowatthour Generated:

Coal Nuclear Overall 126 43 78 1.23.47.83 124 42 85 1.21.47.90 130 36 72 1.27.40.77 136 54 103 1.34.61 1.08 141 48 84 1.39~53.91 RESIDENTIAL SERVICE-AVERAGES: Annual Kwh Use per Customer: With Electric Heating Total Annual Electric Bill: With Electric Heating Total Price per Kwh (in cents): With Electric Heating Total 18,044 10,943 17,907 10,572 6.19 6.76 6.23 6.78$1,117.55$1,115.19$739.99$717.17 17,980 10,559 17,513 10,107 5.72 6.20 6.04 6.65$1,028.26$1,056.91$654.76$672.31 17,702 10,535$1,016.16$658.76 5.74 6.25 NUMBER OF CUSTOMERS:

Year-End: Retail: Residential:

Without Electric Heating With Electric Heating Total Residential Commercial Industrial Miscellaneous Total Retail Wholesale (sales for resale)Total Electric Customers 372,473~7~42 375,929 QQ~3'i 469,875 53,927 5,213~10 475,034 55,077 5,316~17 7 530,821 54 537,224~2 537 286~530 87 369,385 465,180 53,081 5,157~17 525,201 366,835~41 7 461,010 52,542 5,000~17 520,303 364,154~2~7 456,811 51,491 4,847~222 515,375 525257 520356 515428 30 Ig NA MICHIGAN POWER COMPANY AND SUBSIDIARIES DIVIDENDS AND PRICE RANGES OF CUMULATIVE PREFERRED STOCK By Quarters (1996 and 1994)1995-uarters 1994-uarters CUMULAT(VE PREFERRED STOCK 1st 2nd 3rd 4th 1st 2nd 3rd 4th ($100 Par Value)4-1/8/Series Dividends Paid Per Share Market Price-$Per Share (CSE)-High-Low$1.03125$1.03125$1.03125$1.03125$1.03125$1.03125$1.03125$1.03125 4.56/, Series Dividends Paid Per Share Market Price-$Per Share (OTC)Ask-High-Low Bid-High-Low 4.12K Series Dividends Paid Per Share Market Price-$Per Share (OTC)Ask-High-Low Bid-High-Low 46-5/8 45-1/2 47-1/4 46-1/4 47"1/2 47-1/4 49"1/2 47-1/2$1.03$1.03$1.03$1.03 46-1/2 47 43 46 51 46 51 46$1.14$1.14$1.14$1.14 55-5/8 49 54-1/8 45-1/2 50-5/8 45-1/2 46-1/8 45-1/2$1.03$1.03$1.03$1.03 58-1/2 51 54 46-1/2 48 46-1/8 48 43-1/2$1.14$1.14$1.14$1.14 5.90K Series Dividends Paid Per Share Market Price-$Per Share (OTC)Ask (high/low)

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

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

Bid (high/low) 6-7/8/Series Dividends Paid Per Share Market Price-$Per Share (OTC)Ask (high/low)

Bid (high/low)

$1.475$1.475$1.475$1.475$1.475$1.475$1.475$1.475$1.5625$1.5625$1.5625$1.5625$1.5625$1.5625$1.5625$1.5625$1.575$1.575$1.575$1.575$0.9275$1.575$1.575$1.575$1.71875$1.71875$1.71875$1.71875$1.71875$1.71875$1.71875$1.71875 7.08K Series Dividends Paid Per Share Market Price-$Per Share (MYSE)-High-Low 83-5/8 76 88-1/2 91 99"1/2 84 86 86$1.77$1.77$1.77$1.77 97-1/2 95 94 83 87-1/2 80 80 76$1.77$1.77$1.77$1.77 31 INDIANA MICHIGAN POWER COMPANY DIVIDENDS AND PRICE RANGES OF CUMULATIVE PREFERRED STOCK By Quarters (1995 and 1994)(Concluded) 1995-uarters 1994-uarters CUMULATIVE PREFERRED STOCK ($100 Par Value)7.76K Series (Redeened)

Dividends Paid Per Share Market Price-$Per Share (NYSE)-High-Low 1st 2nd 3rd 4th 1st$0.9054 101 100 2nd 3rd 4th 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 quotation Bureau, Inc.Bash indicated quotation not available.(a)Issued February 1994 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 ANNUAL REPORT The Annual Report (Form 10-K)to the Securities and Exchange Commission will be available in April 1996 at no cost to shareholders.

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 CUMULATIVE PREFERRED STOCK First Chicago Trust Company of New York P.O.Box 2534 Suite 4692 Jersey City, NJ 07303-2534 32 Indiana Michigan Power Service Area and the American Electric Power System LAKE MICHIGAN MICHIGAN IAKE ERIE OHIO INDIANA WEST VI RGINIA KENTUCKY VI RG IN I A Indiana Michigan Power Co.area Other AEP operating companies'reas g Major power plant TENNESSEE Cl+prinied on recycled paper ATTACHMENT 2 TO AEP NRC'0909L INDIANA MICHIGAN POWER COMPANY'S PROJECTED CASH FLOW FOR 1996 Indiana Michigan Power Co.1996 Forecasted Sources and Uses of Funds Based on Forecasted Case 9600 Revision 1$Millions Projected 1996 Net Income After Taxes Less Dividends Paid 150.0 122.3 Retained Earnings Adjustments:

Depreciation And Amortization Deferred Operating Costs Deferred Federal Income Taxes and Investment Tax Credits AFUDC Other 27.7 153.8 9.8 (29.2)(1.5)(9.2)Total Adjustments 123.7 Internal Cash Flow 151.4 Average Quarterly Cash Flow 37.9 Average Cash Balances and Short-Term Investments 0.5 Total 38.4 p: 4